Consolidated Natural Gas 10-Q 2007 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2007

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File Number 001-03196

CONSOLIDATED NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

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

120 TREDEGAR STREET RICHMOND, VIRGINIA	23219
(Address of principal executive offices)	(Zip Code)

(804) 819-2000

(Registrant's telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated 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, 2007, 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.

CONSOLIDATED NATURAL GAS COMPANY

INDEX

		Page Number
	PART I. Financial Information
Item 1.	Consolidated Financial Statements
	Consolidated Statements of Income – Three Months Ended March 31, 2007 and 2006	3
	Consolidated Balance Sheets – March 31, 2007 and December 31, 2006	4
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2007 and 2006	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management's Discussion and Analysis of Results of Operations	22
Item 4.	Controls and Procedures	29
	PART II. Other Information
Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	31
Item 5.	Other Information	31
Item 6.	Exhibits	32

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CONSOLIDATED NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2007			2006
(millions)
Operating Revenue
External customers	$	2,271		$	2,623
Affiliated customers		106			198
Total operating revenue		2,377			2,821
Operating Expenses
Purchased gas:
External suppliers		944			1,178
Affiliated suppliers		133			172
Electric energy purchases:
External suppliers		48			31
Affiliated suppliers		11			34
Other energy-related commodity purchases		1			226
Other operations and maintenance:
External suppliers		241			298
Affiliated suppliers		73			50
Depreciation, depletion and amortization		242			216
Other taxes		99			99
Total operating expenses		1,792			2,304
Income from operations		585			517
Other income		8			5
Interest and related charges:
Interest expense		79			61
Interest expense – junior subordinated notes payable to affiliated trust		4			4
Total interest and related charges		83			65
Income from continuing operations before income taxes		510			457
Income tax expense		196			255
Income from continuing operations		314			202
Loss from discontinued operations(1)		(1	)		(1	)
Net Income	$	313		$	201

(1) Net of income tax benefit of $1 million for the three months ended March 31, 2007 and 2006, respectively.

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

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CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2007			December 31, 2006(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	27		$	28
Customer receivables (less allowance for doubtful accounts of $18 and $17)		1,330			1,096
Affiliated receivables		49			127
Other receivables		101			130
Inventories		48			248
Assets held for sale		1,106			1,236
Other		1,382			1,285
Total current assets		4,043			4,150
Investments
Investments in affiliates		162			161
Other		109			106
Total investments		271			267
Property, Plant and Equipment
Property, plant and equipment		20,645			20,146
Accumulated depreciation, depletion and amortization		(7,635	)		(7,420	)
Total property, plant and equipment, net		13,010			12,726
Deferred Charges and Other Assets
Pension and other postretirement benefit assets		1,347			1,317
Other		1,229			1,343
Total deferred charges and other assets		2,576			2,660
Total assets	$	19,900		$	19,803

(1) The Consolidated Balance Sheet at December 31, 2006 has been derived from the audited Consolidated Financial Statements at that date.

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

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CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	March 31, 2007			December 31, 2006(1)
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	199		$	199
Short-term debt		711			752
Accounts payable		1,008			1,175
Payables to affiliates		2,800			2,624
Derivative liabilities		1,324			1,296
Liabilities held for sale		446			480
Other		528			588
Total current liabilities		7,016			7,114
Long-Term Debt
Long-term debt		2,506			2,506
Junior subordinated notes payable to affiliated trust		206			206
Total long-term debt		2,712			2,712
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		3,179			3,049
Other		1,039			1,063
Total deferred credits and other liabilities		4,218			4,112
Total liabilities		13,946			13,938
Commitments and Contingencies (see Note 13)
Common Shareholder’s Equity
Common stock—no par value, 100 shares authorized and outstanding		1,816			1,816
Other paid-in capital		3,338			3,274
Retained earnings		1,190			1,069
Accumulated other comprehensive loss		(390	)		(294	)
Total common shareholder’s equity		5,954			5,865
Total liabilities and shareholder’s equity	$	19,900		$	19,803

(1) The Consolidated Balance Sheet at December 31, 2006 has been derived from the audited Consolidated Financial Statements at that date.

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

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CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2007			2006
(millions)
Operating Activities
Net income	$	313		$	201
Adjustments to reconcile net income to net cash provided by operating activities:
Net realized and unrealized derivative gains		(30	)		(258	)
Depreciation, depletion and amortization		242			218
Deferred income taxes and investment tax credits, net		132			197
Charges related to pending sale of gas distribution subsidiaries		—			167
Other adjustments to net income		(4	)		12
Changes in:
Accounts receivable		(243	)		(81	)
Affiliated accounts receivables and payable		77			(20	)
Inventories		244			280
Deferred purchased gas costs, net		(26	)		94
Accounts payable		(159	)		(380	)
Accrued interest, payroll and taxes		7			38
Margin deposit assets and liabilities		(98	)		(110	)
Pension and other postretirement benefit assets		(30	)		(27	)
Deferred revenue		(23	)		(49	)
Other operating assets and liabilities		39			159
Net cash provided by operating activities		441			441
Investing Activities
Additions to gas and oil properties, including acquisitions		(525	)		(438	)
Plant construction and other property additions		(105	)		(86	)
Acquisition of business, net of cash acquired		—			(91	)
Other		7			(16	)
Net cash used in investing activities		(623	)		(631	)
Financing Activities
Issuance (repayment) of short-term debt, net		(41	)		152
Issuance of affiliated current borrowings, net		399			213
Common dividend payments		(176	)		(191	)
Net cash provided by financing activities		182			174
Increase (decrease) in cash and cash equivalents		—			(16	)
Cash and cash equivalents at beginning of period(1)		32			44
Cash and cash equivalents at end of period(2)	$	32		$	28
Noncash Investing and Financing Activities
Sale of subsidiary to an affiliate in exchange for repayment of affiliated debt	$	208		$	—
Accrued capital expenditures		170			152

(1) 2007 amount includes $4 million of cash classified as held for sale in our Consolidated Balance Sheet.

(2) Includes $5 million and $4 million of cash classified as held for sale in our Consolidated Balance Sheet for 2007 and 2006, respectively.

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

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Consolidated Natural Gas Company (CNG), is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). Our subsidiaries operate in all phases of the natural gas business, explore for and produce gas and oil and provide a variety of energy marketing services. As of March 31, 2007, our regulated gas distribution subsidiaries served approximately 1.7 million residential, commercial and industrial gas sales and transportation customer accounts in Ohio, Pennsylvania and West Virginia and our nonregulated retail energy marketing businesses served approximately 1.5 million residential and commercial gas and electric customer accounts in the Northeast, Mid-Atlantic and Midwest regions of the United States (U.S.). We operate an interstate gas transmission pipeline system, underground natural gas storage system and gathering and extraction facilities in the Northeast, Midwest and Mid-Atlantic states and a liquefied natural gas (LNG) import and storage facility in Maryland. Our producer services operations involve the aggregation of natural gas supply and related wholesale activities. Our exploration and production operations are located in several major gas and oil producing basins in the U.S., both onshore and offshore.

We manage our daily operations through three primary operating segments: Delivery, Energy and Exploration & Production (E&P). In addition, we report our corporate and other functions as a segment. Our assets remain wholly owned by us and our legal subsidiaries.

The terms “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, CNG, one of CNG’s consolidated subsidiaries or operating segments or the entirety of CNG 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 (GAAP). These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2006.

In our opinion, our accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals necessary to present fairly our financial position as of March 31, 2007, and our results of operations and cash flows for the three months ended March 31, 2007 and 2006.

We make certain estimates and assumptions in preparing our Consolidated Financial Statements in accordance with 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 accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, our accounts and those of our majority-owned subsidiaries and those variable interest entities (VIEs) where we have been determined to be the primary beneficiary.

In accordance with GAAP, we report certain contracts and instruments at fair value. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, we estimate 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 our Annual Report on Form 10-K for the year ended December 31, 2006 for a more detailed discussion of our estimation techniques.

The results of operations for 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, purchased gas expenses and other factors.

Certain amounts in our 2006 Consolidated Financial Statements and Notes have been recast to conform to the 2007 presentation.

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Note 3. Newly Adopted Accounting Standards

FIN 48

We adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 48,Accounting for Uncertainty in Income Taxes (FIN 48), on January 1, 2007. As a result of the implementation of FIN 48, we recorded a $16 million charge to beginning retained earnings, representing the cumulative effect of the change in accounting principle.

Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because, in accordance with FIN 48, management has either measured the tax benefit at an amount less than the benefit claimed, or expected to be claimed, or concluded that it is not more-likely-than-not that the tax position will be ultimately sustained. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of an income tax refund receivable, an increase in deferred tax liabilities, or a decrease in deferred tax assets. Noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities; current payables are included in other current liabilities, except when such amounts are presented net with amounts receivable from or amounts prepaid to taxing authorities in other current assets. As of January 1, 2007, unrecognized tax benefits totaled $75 million. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Unrecognized tax benefits as of January 1, 2007, included $12 million that, if recognized, would lower the effective tax rate. Through March 31, 2007, there have been no significant changes in our unrecognized tax benefits.

Consistent with our existing policies, we continue to recognize estimated interest payable on underpayments of income taxes in interest expense and estimated penalties that may result from the settlement of uncertain tax positions in other income. As of January 1, 2007, we had accrued approximately $4 million for interest receivable and no amounts for penalties.

As of January 2000, we began filing a consolidated U.S. federal income tax return and participating in an intercompany tax sharing agreement with Dominion and its subsidiaries. In addition, where applicable, we participate in combined income tax returns with Dominion and its subsidiaries in various states; otherwise, we file separate state income tax returns for our subsidiaries.

For U.S. federal income taxes, the statute of limitations for tax years prior to 2000 has expired, except for tax year 1998, for which the statute of limitations is scheduled to expire in September 2007, and tax years 1996 and 1997, for which we have reserved the right to file a claim for refund for certain tax credits.

We are currently engaged in settlement negotiations with the Appellate Division of the Internal Revenue Service (IRS) regarding certain adjustments proposed during the examination of tax years 2000 and 2001. Settlement negotiations could possibly conclude later this year, but no significant change in unrecognized tax benefits is expected to result. In addition, the examination of our 2002 and 2003 returns by the IRS is expected to be completed by July 2007. We have evaluated and agreed to some of the adjustments and expect to pay any liability resulting from those adjustments after completion of the examination; however, no significant change in unrecognized tax benefits is expected to result. At this time, we cannot estimate the impact on unrecognized tax benefits that could result in the next twelve months from additional payments that may be made for adjustments remaining in dispute or any newly proposed adjustments.

Dominion’s combined income tax returns filed with Virginia for 2003 and subsequent years remain subject to examination by taxing authorities, and 2000 is the earliest tax year remaining open for examination of returns filed with Pennsylvania. We are also obligated to report adjustments resulting from IRS settlements of earlier years to state taxing authorities. In addition, if state net operating losses or credits, generated in years for which the statute of limitations has expired, are utilized, the determination of such amounts is subject to examination by state taxing authorities.

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EITF 04-13

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 and to facilitate gas transportation. In September 2005, the FASB ratified the Emerging Issues Task Force’s (EITF) consensus on Issue No. 04-13,Accounting for Purchases and Sales of Inventory with the Same Counterparty (EITF 04-13), that requires buy/sell and related agreements to be presented on a net basis in the Consolidated Statements of Income if they are entered into in contemplation of one another. We adopted the provisions of EITF 04-13 on April 1, 2006 for new arrangements entered into, and modifications or renewals of existing arrangements after that date. As a result, a significant portion of our activity related to buy/sell arrangements is presented on a net basis in our Consolidated Statement of Income for the three months ended March 31, 2007; however, there was no impact on our results of operations or cash flows. Pursuant to the transition provisions of EITF 04-13, activity related to buy/sell arrangements that were entered into prior to April 1, 2006, and have not been modified or renewed after that date, continue to be reported on a gross basis and are summarized below:

	Three Months Ended March 31,
	2007		2006
(millions)
Sale activity included in operating revenue	$	34	$	280
Purchase activity included in operating expenses(1)		37		278

(1) Included in other energy-related commodity purchases expense and purchased gas expense in our Consolidated Statements of Income.

EITF 06-3

Effective January 1, 2007, EITF Issue No. 06-3,How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation), requires certain disclosures if an entity collects any tax assessed by a governmental authority that is both imposed on and concurrent with a specific revenue-producing transaction between the entity, as a seller, and its customers. We collect sales taxes but exclude such amounts from revenue.

Note 4. Recently Issued Accounting Standards

SFAS No. 157

In September 2006, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 157,Fair Value Measurements (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The provisions of SFAS No. 157 will become effective for us beginning January 1, 2008. Generally, the provisions of this statement are to be applied prospectively. Certain situations, however, require retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application is required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses under EITF Issue No. 02-3,Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activitiesand SFAS No. 155, Accounting for Certain Hybrid Financial Instruments.We are currently evaluating the impact that SFAS No. 157 will have on our results of operations and financial condition.

SFAS No. 159

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159).SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each eligible item. The provisions of SFAS No. 159 will become effective for us beginning January 1, 2008. We are currently evaluating the impact that SFAS No. 159 may have on our results of operations and financial condition.

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EITF 06-4

In September 2006, the FASB ratified the consensus reached by the EITF on Issue No. 06-4,Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements (EITF 06-4). EITF 06-4 specifies that if an employer provides a benefit to an employee under an endorsement split-dollar life insurance arrangement that extends to postretirement periods, it should recognize a liability for future benefits in accordance with SFAS No. 106,Employers' Accounting for Postretirement Benefits Other Than Pensions (if, in substance, a postretirement benefit plan exists) or Accounting Principles Board Opinion No. 12,Deferred Compensation Contracts (if the arrangement is, in substance, an individual deferred compensation contract) based on the substantive agreement with the employee. We have certain insurance policies subject to the provisions of EITF 06-4 and are currently evaluating the impact that EITF 06-4 may have on our results of operations and financial condition. The provisions of EITF 06-4 will become effective for us beginning January 1, 2008.

Note 5. Operating Revenue

Our operating revenue consists of the following:

	Three Months Ended March 31,
	2007		2006
(millions)
Gas sales:
Regulated	$	559	$	800
Nonregulated:
External customers		687		618
Affiliated customers		101		193
Nonregulated electric sales		76		95
Other energy-related commodity sales		89		317
Gas transportation and storage		353		288
Gas and oil production		478		478
Other		34		32
Total operating revenue	$	2,377	$	2,821

Note 6. Income Taxes

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

	Three Months Ended March 31,
	2007		2006
U.S. statutory rate	35.0	%	35.0	%
Increases (decreases) resulting from:
Employee pension and other benefits	(0.2	)	(0.5	)
State taxes, net of federal benefit	3.2		3.4
Other, net	(0.1	)	(0.1	)
Subtotal	37.9		37.8
Changes in valuation allowances	—		(5.4	)
Recognition of deferred taxes – stock of subsidiaries held for sale	0.5		23.5
Effective tax rate	38.4	%	55.9	%

The change in our effective tax rate is primarily attributable to the absence of a 2006 tax benefit from the partial reversal of previously recorded valuation allowances on certain federal and state tax loss carryforwards ($25 million), since these carryforwards are expected to be utilized to offset capital gain income that is expected to be generated from the pending sale of The Peoples Natural Gas Company (Peoples) and Hope Gas, Inc. (Hope). This benefit was more than offset by the establishment of $107 million of deferred tax liabilities in 2006, associated with the excess of our financial reporting basis over the tax basis in the stock of Peoples and Hope, 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). Although these subsidiaries are not classified as discontinued operations, 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 this difference will reverse in the

PAGE 10

foreseeable future. We recorded a charge, since the financial reporting basis of our investment in Peoples and Hope exceeded our tax basis. This difference and related deferred taxes will reverse and will partially offset current tax expense that will be recognized upon closing of the sale.

Note 7. Comprehensive Income

The following table presents total comprehensive income:

	Three Months Ended March 31,
	2007			2006
(millions)
Net income	$	313		$	201
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		(96	)		356	(1)
Total comprehensive income	$	217		$	557

(1) Primarily due to the settlement of certain commodity derivative contracts and favorable changes in fair value resulting from a decrease in gas prices.

Note 8. Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of natural gas, oil, electricity and other energy-related products, as well as the interest rate risks of our business operations. We use derivative instruments to mitigate our exposure to these risks and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes as allowed by SFAS No. 133, Accounting for Derivatives and Hedging Activities. Selected information about our hedge accounting activities follows:

	Three Months Ended March 31,
	2007		2006
(millions)
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$	4	$	(1	)
Cash flow hedges		15		17
Net ineffectiveness	$	19	$	16

For the three months ended March 31, 2007 and 2006, the portion of gains or losses on hedging instruments excluded from the measurement of effectiveness and included in net income were not material.

The following table presents selected information related to cash flow hedges included in accumulated other comprehensive income (AOCI) in our Consolidated Balance Sheet at March 31, 2007:

	AOCI After-Tax			Portion Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(224	)	$	(212	)	48 months
Oil		(230	)		(182	)	33 months
Other		(7	)		(7	)	2 months
Interest Rate		(1	)		—		92 months
Total	$	(462	)	$	(401	)

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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 9.Dispositions

Sale of Merchant Generation Facility

In December 2006, we reached an agreement with an entity jointly owned by Tenaska Power Fund, L.P. and Warburg Pincus LLC to sell Armstrong, our 625-megawatt natural gas-fired merchant generation peaking facility located in Shelocta, Pennsylvania. In February 2007, an affiliate acquired from Armstrong a majority equity interest in exchange for a reduction in net amounts owed to the affiliate of approximately $207 million. Immediately following this transaction, we sold our remaining minority interest in Armstrong to the affiliate, which subsequently sold Armstrong in March 2007. We recorded a $2 million ($1 million after-tax) loss from the discontinued operations of this facility prior to the sale. There was no gain or loss recognized upon disposition.

The carrying amounts of the major classes of assets and liabilities classified as held for sale in our Consolidated Balance Sheet at December 31, 2006, were comprised of property, plant and equipment, net ($115 million), inventory ($4 million) and accounts payable ($2 million).

The following table presents selected information regarding the results of operations of Armstrong, which is reported as a discontinued operation in our Consolidated Statements of Income:

	Three Months Ended March 31,
	2007			2006
(millions)
Operating Revenue	$	3		$	4
Loss before income taxes		(2	)		(2	)

Sale of Regulated Gas Distribution Subsidiaries

On March 1, 2006, we entered into an agreement with Equitable Resources, Inc., to sell two of our wholly-owned regulated gas distribution subsidiaries, Peoples and 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 end of the second quarter of 2007, subject to regulatory approval as discussed inOther Matters in Item 2. Management’s Discussion and Analysis of Results of Operations. The carrying amounts of the major classes of assets and liabilities classified as held for sale in our Consolidated Balance Sheets are as follows:

	March 31, 2007			December 31, 2006
(millions)
ASSETS
Current Assets
Cash	$	5		$	4
Customer receivables		179			144
Unrecovered gas costs		28			31
Other		38			90
Total current assets		250			269
Investments		2			2
Property, Plant and Equipment
Property, plant and equipment		1,114			1,108
Accumulated depreciation, depletion and amortization		(368	)		(370	)
Total property, plant and equipment, net		746			738
Deferred Charges and Other Assets
Regulatory assets		105			106
Other		3			2
Total deferred charges and other assets		108			108
Assets held for sale	$	1,106		$	1,117

PAGE 12

	March 31, 2007		December 31, 2006
(millions)
LIABILITIES
Current Liabilities
Accounts payable	$	61	$	90
Payables to affiliates		27		40
Accrued taxes		23		23
Deferred income taxes		2		9
Other		92		74
Total current liabilities		205		236
Deferred Credits and Other Liabilities
Asset retirement obligations		38		38
Deferred income taxes and investment tax credits		187		187
Regulatory liabilities		11		10
Other		5		7
Total deferred credits and other liabilities		241		242
Liabilities held for sale	$	446	$	478

The following table presents selected information regarding the results of operations of Peoples and Hope:

	Three Months Ended March 31,
	2007		2006
(millions)
Operating Revenue	$	309	$	357
Income (loss) before income taxes		54		(128	)

In March 2006, we recognized a $159 million ($94 million after-tax) charge, recorded in other operations and maintenance expense in our Consolidated Statement 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 was no longer probable. We also have established $107 million of deferred tax liabilities in our Consolidated Balance Sheet in accordance with EITF 93-17.

Note 10. Ceiling Test

We follow the full cost method of accounting for gas and oil E&P 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 7% 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, 2007.

Note 11. Variable Interest Entities

In 2006, we, along with three other gas and oil exploration companies, entered into a long-term contract with an unrelated limited liability company (LLC) whose only current activities are to design, construct, install and own the Thunder Hawk facility, a semi-submersible production facility to be located in the deepwater Gulf of Mexico. Certain variable pricing terms and guarantees in the contract protect the equity holder from variability, and therefore, the LLC was determined to be a VIE. After completing our analysis under FASB Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities, we concluded that although our 25% interest in the contract, as a result of its pricing terms and guarantee, represents a variable interest in the LLC, we are not the primary beneficiary. Our maximum exposure to loss from the contractual arrangement is approximately $63 million. As of March 31, 2007, we have not made any payments to the LLC.

PAGE 13

Note 12. Significant Financing Transactions

Joint Credit Facilities

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. Short-term financing is provided by a $3.0 billion five-year joint revolving credit facility dated February 2006 with Dominion and Virginia Electric and Power Company (Virginia Power), a wholly-owned subsidiary of Dominion. The 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 31, 2007, total outstanding commercial paper supported by the joint credit facility was $2.0 billion, none of which was borrowed on our behalf. At March 31, 2007, total outstanding letters of credit supported by the joint credit facility were $299 million, none of which were issued on our behalf.

At March 31, 2007, capacity available under the joint credit facility was $723 million.

Other Credit Facilities

Our short-term financing is also supported by an amended and restated $1.7 billion five-year revolving credit facility dated February 2006, which is scheduled to terminate in August 2010. This credit facility is being used to support our issuance of commercial paper and letters of credit to provide collateral required by counterparties on derivative contracts used in risk management strategies for our gas and oil production. At March 31, 2007, outstanding commercial paper supported by this facility totaled $211 million. At March 31, 2007, outstanding letters of credit totaled $307 million and outstanding bank borrowings totaled $500 million under this facility. At March 31, 2007, capacity available under the facility was $682 million.

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 risk management strategies for our gas and oil production operations. At March 31, 2007, we had the following letter of credit facilities:

Facility Limit	Outstanding Letters of Credit		Facility Capacity Available		Facility Inception Date	Facility Maturity Date
(millions)
$100(1)	$	—	$	100	June 2004	June 2007
100		100		—	August 2004	August 2009
200(2)		—		200	December 2005	December 2010
$400	$	100	$	300

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

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

Note 13. Commitments and Contingencies

Other than the matters discussed below, there have been no significant developments regarding commitments and contingencies disclosed in Note 20 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006, nor have any significant new matters arisen during the three months ended March 31, 2007.

PAGE 14

Litigation

In 2006, Gary P. Jones and others filed suit against Dominion Transmission. Inc. (DTI), Dominion Exploration & Production, Inc. (DEPI) and Dominion Resources Services, Inc. (DRS), a wholly-owned subsidiary of Dominion. The plaintiffs are royalty owners, seeking to recover damages as a result of the Dominion defendants allegedly underpaying royalties by improperly deducting post-production costs and not paying fair market value for the gas produced from their leases. The plaintiffs seek class action status on behalf of all West Virginia residents and others who are parties to or beneficiaries of oil and gas leases with the Dominion defendants. DRS is erroneously named as a defendant as the parent company of DTI and DEPI. In the first quarter of 2007, we established a litigation reserve representing our best estimate of the probable loss related to this matter. We do not believe that the final resolution of this matter will have a material adverse effect on our results of operations or financial condition.

Guarantees

We 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, 2007. 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, 2007, 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)		1,131		443
Other		327		250
Total	$	1,663	$	1,391

(1) Represents the estimated portion of the guarantees’ stated limit that is utilized as of March 31, 2007 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) Performance and payment guarantees related to an offshore day work drilling contract, rig share agreements and related services for certain subsidiaries. There are no stated limits for these guarantees.

(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, oil, pipeline capacity, transportation 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 required 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.

Surety Bonds and Letters of Credit

As of March 31, 2007, we had purchased $50 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $407 million. We enter into these arrangements to facilitate commercial transactions by our subsidiaries with third parties.

Note 14. Credit Risk

Credit risk is our risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, Dominion and its subsidiaries, including us, maintain credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our March 31, 2007 provision for credit losses, that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

PAGE 15

We sell natural gas and provide distribution services to residential, commercial and industrial customers and provide transmission services to utilities and other energy companies. In addition, we enter into contracts with various companies in the energy industry for purchases and sales of energy-related commodities, including natural gas and oil. Except for our E&P business activities, these transactions principally occur in the Northeast, Mid-Atlantic and Midwest regions of the U.S. We do not believe that this geographic concentration contributes significantly to our overall exposure to credit risk. In addition, as a result of our large and diverse customer base, we are not exposed to a significant concentration of credit risk for receivables arising from gas utility operations, including transmission services and retail energy sales.

Our exposure to credit risk is concentrated primarily within our sales of gas and oil production, extracted products and energy marketing, including our hedging activities, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At March 31, 2007, our gross credit exposure totaled $378 million. Of this amount, investment grade counterparties represented 78% and no single counterparty exceeded 8%. We held no collateral for these transactions at March 31, 2007.

Note 15. Related Party Transactions

We engage in related party transactions primarily with affiliates (Dominion subsidiaries). Our 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. We are included in Dominion’s consolidated federal income tax return and participate in certain Dominion benefit plans. A discussion of significant related party transactions follows:

Transactions with Affiliates

We transact with affiliates for certain quantities of natural gas, electricity and other commodities at fixed and market prices in the ordinary course of business. We also enter into certain financial commodity derivative 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 and other energy-related commodities. We designate the majority of these contracts as cash flow or fair value hedges for accounting purposes.

At March 31, 2007 and December 31, 2006, our Consolidated Balance Sheets include derivative assets with affiliates of $87 million and $188 million, respectively, and derivative liabilities with affiliates of $54 million and $215 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 in our Consolidated Balance Sheets.

DRS provides certain administrative and technical services to us, which totaled $50 million and $49 million in the three months ended March 31, 2007 and 2006, respectively. We provide certain services to other affiliates, including technical services to other Dominion subsidiaries, which totaled $4 million and $3 million in the three months ended March 31, 2007 and 2006, respectively.

Presented below are significant 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,
	2007		2006
(millions)
Sales of natural gas	$	101	$	193
Loss on commodity derivative contracts		27		4
Purchases of natural gas		133		172
Purchases of electric energy		11		34

PAGE 16

We have borrowed funds from Dominion under short-term borrowing arrangements. At March 31, 2007 and December 31, 2006, our outstanding borrowings, net of repayments, under the Dominion money pool totaled $2.6 billion and $2.3 billion, respectively, included in payables to affiliates in our Consolidated Balance Sheets. Net interest charges incurred by us related to these borrowings were $35 million and $26 million in the three months ended March 31, 2007 and 2006, respectively.

In November 2006, we issued a $234 million short-term note payable to one of our affiliates in connection with their repayment of long-term debt associated with our Armstrong facility. In February 2007, an affiliate acquired from Armstrong, a majority equity interest in exchange for a reduction in net amounts owed to the affiliate of approximately $207 million. Immediately following this transaction, we sold our remaining interest in Armstrong to the affiliate.

Note 16. Employee Benefit Plans

The components of the provision for net periodic benefit cost for employees represented by collective bargaining units were as follows:

	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31,	2007			2006			2007			2006
(millions)
Service cost	$	3		$	3		$	2		$	4
Interest cost		9			8			5			7
Expected return on assets		(30	)		(26	)		(6	)		(5	)
Amortization of prior service credit		—			—			(1	)		(1	)
Amortization of transition obligation		—			—			1			1
Amortization of net loss		—			—			1			3
Curtailments(1)		—			—			—			3
Net periodic benefit (credit) cost	$	(18	)	$	(15	)	$	2		$	12

(1) Relates to the pending sale of Peoples and Hope.

Pension benefits, for our employees not represented by collective bargaining units, are covered by Dominion’s pension plan, which provides benefits to multiple Dominion subsidiaries. We recognized $13 million and $12 million of net periodic pension credits for the three months ended March 31, 2007 and 2006, respectively, related to this plan. Retiree health care and life insurance benefits, for our employees not represented by recognized bargaining units, are covered by Dominion’s other postretirement benefit plans. Our net periodic benefit cost related to these plans was $3 million and $7 million for the three months ended March 31, 2007 and 2006, respectively.

Employer Contributions

We made no contributions to our defined benefit pension plans or other postretirement benefit plans during the first quarter of 2007. We expect to contribute approximately $13 million to our other postretirement benefit plans during the remainder of 2007. Under our funding policies, we evaluate pension and other postretirement benefit plan funding requirements annually, usually in the second half of the year after receiving updated plan information from our actuary. Based on the funded status of each plan and other factors, the amount of additional contributions to be made in 2007 will be determined at that time.

PAGE 17

Note 17. Condensed Consolidating Financial Information

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 and are reflected in current liabilities at March 31, 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 Consolidating Statement of Income Information

Three Months Ended March 31,	CNG (Parent Company)			DOTEPI		Other Subsidiaries			Adjustments & Eliminations			Consolidated
2007
(millions)
Operating revenue	$	—		$	240	$	2,329		$	(192	)	$	2,377
Operating expense		1			148		1,831			(188	)		1,792
Income (loss) from operations		(1	)		92		498			(4	)		585
Other income		55			—		13			(60	)		8
Interest and related charges		58			27		58			(60	)		83
Income (loss) from continuing operations before income tax expense		(4	)		65		453			(4	)		510
Income tax expense		—			23		174			(1	)		196
Equity in earnings of subsidiaries		317			—		—			(317	)		—
Loss from discontinued operations		—			—		(1	)		—			(1	)
Net income	$	313		$	42	$	278		$	(320	)	$	313
2006
Operating revenue	$	—		$	181	$	2,811		$	(171	)	$	2,821
Operating expense		1			136		2,324			(157	)		2,304
Income (loss) from operations		(1	)		45		487			(14	)		517
Other income		60			—		5			(60	)		5
Interest and related charges		53			14		59			(61	)		65
Income from continuing operations before income tax expense		6			31		433			(13	)		457
Income tax expense		109			16		136			(6	)		255
Equity in earnings of subsidiaries		304			—		—			(304	)		—
Loss from discontinued operations		—			—		(1	)		—			(1	)
Net income	$	201		$	15	$	296		$	(311	)	$	201

PAGE 18

Condensed Consolidating Balance Sheet Information

At March 31,	CNG (Parent Company)		DOTEPI		Other Subsidiaries		Adjustments & Eliminations			Consolidated
2007
(millions)
Assets
Current assets	$	2,171	$	415	$	3,781	$	(2,324	)	$	4,043
Investment in affiliates		5,812		—		99		(5,749	)		162
Other investments		106		—		4		(1	)		109
Loans to affiliates		1,562		—		—		(1,562	)		—
Property, plant and equipment, net		—		4,762		9,103		(855	)		13,010
Deferred charges and other assets		26		550		2,117		(117	)		2,576
Total assets	$	9,677	$	5,727	$	15,104	$	(10,608	)	$	19,900
Liabilities & Shareholder���s Equity
Current liabilities	$	985	$	2,791	$	6,169	$	(2,929	)	$	7,016
Long-term debt		2,506		—		—		—			2,506
Notes payable to affiliates		206		—		1,562		(1,562	)		206
Deferred credits and other liabilities		26		1,234		3,263		(305	)		4,218
Common shareholder’s equity		5,954		1,702		4,110		(5,812	)		5,954
Total liabilities and shareholder’s equity	$	9,677	$	5,727	$	15,104	$	(10,608	)	$	19,900
At December 31,
2006
(millions)
Assets
Current assets	$	2,143	$	266	$	3,993	$	(2,252	)	$	4,150
Investment in affiliates		5,707		—		98		(5,644	)		161
Other investments		105		—		3		(2	)		106
Loans to affiliates		1,562		—		—		(1,562	)		—
Property, plant and equipment, net		—		4,585		8,964		(823	)		12,726
Deferred charges and other assets		21		571		2,218		(150	)		2,660
Total assets	$	9,538	$	5,422	$	15,276	$	(10,433	)	$	19,803
Liabilities & Shareholder’s Equity
Current liabilities	$	953	$	2,522	$	6,468	$	(2,829	)	$	7,114
Long-term debt		2,506		—		—		—			2,506
Notes payable to affiliates		206		—		1,562		(1,562	)		206
Deferred credits and other liabilities		8		1,163		3,279		(338	)		4,112
Common shareholder’s equity		5,865		1,737		3,967		(5,704	)		5,865
Total liabilities and shareholder’s equity	$	9,538	$	5,422	$	15,276	$	(10,433	)	$	19,803

Condensed Consolidating Statement of Cash Flow Information

Three Months Ended March 31,	CNG (Parent Company)			DOTEPI			Other Subsidiaries			Adjustments & Eliminations			Consolidated
2007
(millions)
Net cash provided by operating activities	$	184		$	—		$	523		$	(266	)	$	441
Net cash provided by (used in) investing activities		33			(250	)		(326	)		(80	)		(623	)
Net cash provided by (used in) financing activities		(217	)		244			(191	)		346			182
2006
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

PAGE 19

Note 18. Operating Segments

We are organized primarily on the basis of products and services sold in the United States. We manage our operations through the following segments:

Deliveryincludes our regulated gas distribution and customer service businesses which are subject to cost-of-service rate regulation and accordingly, apply SFAS No. 71,Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).It also includes our nonregulated retail energy marketing operations.

Energy includes our regulated natural gas transmission pipeline and underground natural gas storage businesses and an LNG facility that are subject to cost-of-service rate regulation and accordingly, apply SFAS No. 71. It also includes gathering and extraction facilities, certain Appalachian natural gas production and producer services, which consist of aggregation of gas supply and related wholesale activities.

E&P includes our gas and oil exploration, development and production operations. 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, West Texas, Mid-Continent, the Rockies and Appalachia.

Corporateincludes our corporate functions, the net impact of the discontinued operation of our Armstrong 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, 2007, the Corporate segment included $21 million of net expenses attributable to our operating segments. The net expenses in 2007 primarily related to the impact of the following:

• A $21 million ($13 million after-tax) charge resulting from the accrual of litigation reserves, attributable to the E&P segment ($7 million after-tax) and the Energy segment ($6 million after-tax);

• $7 million ($5 million after-tax) of incremental expenses related to retention agreements associated with the potential disposition of substantially all of our E&P assets, attributable to the E&P segment; and

• A $2 million after-tax charge associated with the write-off of certain regulatory assets related to the pending sale of Peoples and Hope, attributable to the Delivery segment.

In the three months ended March 31, 2006, the Corporate segment included $106 million of net expenses attributable to our operating segments. The net expenses in 2006 primarily related to the impact of the following:

• 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, attributable to the Delivery segment; and

• $10 million ($7 million after-tax) of incremental expenses associated with Hurricanes Katrina and Rita (2005 hurricanes), attributable to the E&P segment.

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

PAGE 20

The following table presents segment information pertaining to our operations:

	Delivery		Energy		E&P		Corporate			Adjustments & Eliminations			Consolidated Total
(millions)
Three Months Ended March 31,
2007
Operating revenue:
External customers	$	1,309	$	394	$	568	$	—		$	—		$	2,271
Affiliated customers		7		97		2		—			—			106
Intersegment		4		79		45		—			(128	)		—
Total operating revenue		1,320		570		615		—			(128	)		2,377
Loss from discontinued operations, net of tax		—		—		—		(1	)		—			(1	)
Net income (loss)		134		89		113		(23	)		—			313
2006
Operating revenue:
External customers	$	1,385	$	428	$	810	$	—		$	—		$	2,623
Affiliated customers		—		195		3		—			—			198
Intersegment		1		90		53		—			(144	)		—
Total operating revenue		1,386		713		866		—			(144	)		2,821
Loss from discontinued operations, net of tax		—		—		—		(1	)		—			(1	)
Net income (loss)		85		88		213		(185	)		—			201

Note 19. Subsequent Event

In April 2007, Dominion entered into an agreement with Eni Petroleum Co. Inc. (Eni Petroleum) to sell substantially all of our offshore E&P operations for approximately $4.76 billion. The transaction is expected to close by early July 2007, subject to customary closing conditions and adjustments. Our offshore operations include approximately 967 billion cubic feet equivalent (bcfe) of proved natural gas and oil reserves in the outer continental shelf and deepwater areas of the Gulf of Mexico at December 31, 2006. Of this total, approximately 961 bcfe are being sold to Eni Petroleum. The effective date for the sale is June 30, 2007. Eni Petroleum’s obligations under the agreement are guaranteed by its parent company, Eni S.p.A. Remaining offshore E&P operations are expected to be disposed of in a separate transaction by early July 2007.

Dominion continues to pursue the potential disposition of our U.S. onshore E&P operations, excluding those in the Appalachian Basin. Net cash proceeds from this disposition and any future dispositions will be used to reduce debt, acquire assets related to our remaining businesses and for other corporate purposes, including the payment of dividends to Dominion.

The offshore disposition will result in an initial pre-tax charge of approximately $370 million, which will be reported in second quarter 2007 earnings. This reflects the discontinuance of hedge accounting for certain cash flow hedges related to our offshore E&P operations since it became probable that the forecasted sales of gas and oil will not occur. In connection with the discontinuance of hedge accounting for these contracts, we will reclassify approximately $370 million of pre-tax losses from AOCI to earnings. We have entered into offsetting positions for these gas and oil derivatives that will minimize the volatility that would have resulted from these contracts being marked to market through earnings. We expect that this charge will be more than offset by the gain we ultimately expect to recognize on the disposition.

In addition to this initial charge, we anticipate recording additional charges related to the disposition plan that are not currently estimable. These charges will include cash expenditures for transaction costs, including employee-related, legal and other costs.

PAGE 21

CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Results of Operations (MD&A) discusses the results of operations and general financial condition of Consolidated Natural Gas Company. MD&A should be read in conjunction with the Consolidated Financial Statements. The terms “Company,” “we,” “our” and “us” are used throughout MD&A and, depending on the context of 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. We are a wholly-owned subsidiary of Dominion.

Contents of MD&A

Our MD&A consists of the following information:

• Forward-Looking Statements

• Accounting Matters

• Results of Operations

• Segment Results of Operations

• Credit Risk

• Other Matters

Forward-Looking Statements

This report contains statements concerning our 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 such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may” or other similar words.

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

• Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;

• Extreme weather events, including hurricanes and winter storms, that can cause outages, production delays and property damage to our facilities;

• State and federal legislative and regulatory developments and changes to environmental and other laws and regulations, including those related to climate change to which we are subject;

• Cost of compliance with environmental laws and regulations, including those costs related to climate change;

• Fluctuations in energy-related commodity prices and the effect they could have on our earnings, liquidity position and the underlying value of our assets;

• Counterparty credit risk;

• Capital market conditions, including price risk due to marketable securities held as investments in benefit plan trusts;

• Fluctuations in interest rates;

• Change in rating agency requirements or credit ratings and their effect on availability and cost of capital;

• Changes in financial or regulatory accounting 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, including our divestiture of Peoples and Hope, the divestiture of our offshore E&P operations and any divestiture of our other E&P operations;

• Risks associated with any realignment of our operating assets, including a reduction to future earnings, costs associated with the disposition of our offshore E&P operations and any disposition of our other E&P operations, as well as the costs and reinvestment risks related to the deployment of proceeds from any disposition;

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

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• Additional risk exposure associated with the termination of business interruption and offshore property damage insurance related to our E&P operations and our inability to replace such insurance on commercially reasonable terms.

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, 2006.

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.

Accounting Matters

Critical Accounting Policies and Estimates

As of March 31, 2007, there have been no significant changes with regard to critical accounting policies and estimates as disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2006. The policies disclosed included the accounting for derivative contracts at fair value, goodwill impairment testing, long-lived asset impairment testing, employee benefit plans, regulated operations, gas and oil operations and income taxes.

Other

See Notes 3 and 4 to our Consolidated Financial Statements for a discussion of newly adopted and recently issued accounting standards.

Results of Operations

Presented below is a summary of our consolidated results for the quarter ended March 31, 2007 and 2006:

	2007		2006		$ Change
(millions)
First Quarter
Net income	$	313	$	201	$	112

Overview

First Quarter 2007 vs. 2006

Net income increased by 56% to $313 million. Favorable drivers include the absence of 2006 tax adjustments and write-off of certain regulatory assets in connection with the pending sale of two of our wholly-owned regulated gas distribution subsidiaries, Peoples and Hope. Unfavorable drivers include the absence of a 2006 benefit resulting from favorable changes in the fair value of certain gas and oil hedges that were de-designated following the 2005 hurricanes.

Analysis of Consolidated Operations

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

	First Quarter
	2007		2006		$ Change
(millions)
Operating Revenue	$	2,377	$	2,821	$	(444	)
Operating Expenses:
Purchased gas		1,077		1,350		(273	)
Electric energy purchases		59		65		(6	)
Other energy-related commodity purchases		1		226		(225	)
Other operations and maintenance		314		348		(34	)
Depreciation, depletion and amortization		242		216		26
Other taxes		99		99		—
Other income		8		5		3
Interest and related charges		83		65		18
Income tax expense		196		255		(59	)

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An analysis of our results of operations for the first quarter of 2007 compared to the first quarter of 2006 follows:

First Quarter 2007 vs. 2006

Operating Revenuedecreased 16% to $2.4 billion, primarily reflecting:

• A $241 million decrease from regulated gas distribution operations, primarily reflecting a $188 million decrease resulting from the migration of customers to energy choice programs and a $184 million decrease primarily reflecting lower gas prices, partially offset by a $131 million increase associated with comparably colder weather and changes in customer usage and other factors. This decrease was largely offset by a corresponding decrease inPurchased gas expense;

• A $232 million decrease in sales of purchased oil by E&P operations, primarily due to the impact of netting sales and purchases of oil under buy/sell arrangements associated with the implementation of EITF 04-13 in 2006. This decrease in sales of purchased oil was largely offset by a corresponding decrease inOther energy-related commodity purchases expense; and

• A $139 million decrease from gas related activities of our producer services business, as a result of a decrease in both volumes ($60 million) and prices ($79 million) associated with gas aggregation.

These decreases were partially offset by:

• A $113 million increase in gas sales by our retail energy marketing operations, primarily resulting from increased customer accounts ($196 million), partially offset by lower contracted sales prices ($83 million); and

• A $65 million increase in gas transportation and storage revenue from our gas distribution operations due to increased volumes ($41 million) and higher prices ($24 million).

Operating Expenses and Other Items

Purchased gas expensedecreased 20% to $1.1 billion, primarily resulting from:

• A $200 million decrease attributable to gas distribution operations, due primarily to lower average gas prices; and

• A $128 million decrease associated with our producer services business, due to lower prices ($68 million) and volumes ($60 million); partially offset by

• A $93 million increase associated with retail energy marketing operations, primarily due to increased volumes ($200 million), partially offset by decreased prices ($107 million).

Electric energy purchases expense decreased 9% to $59 million, primarily resulting from a decrease in purchases by our retail energy marketing operations related to the loss of a wholesale supply contract.

Other energy-related commodity purchases expense decreased to $1 million as a result of the impact of netting sales and purchases of oil under buy/sell arrangements in accordance with EITF 04-13, as discussed inOperating Revenue.

Other operations and maintenance expense decreased 10% to $314 million, primarily reflecting the following:

• The absence of a $159 million charge in 2006 associated with the write-off of certain regulatory assets related to the pending sale of Peoples and Hope; and

• A $35 million decrease resulting from price risk management activities, primarily associated with our retail energy marketing operations.

These decreases were partially offset by:

• The absence of a $118 million benefit in 2006 resulting from favorable changes in the fair value of certain gas and oil hedges that were de-designated following the 2005 hurricanes;

• A $21 million charge resulting from the accrual of litigation reserves; and

• A $20 million increase in bad debt expense, primarily reflecting expenses for gas distribution operations related to low income energy assistance programs. These expenditures are recovered through rates.

Depreciation, depletion and amortization expense (DD&A) increased 12% to $242 million, primarily reflecting higher E&P finding and development costs and increased gas production.

Interest and related charges increased 28% to $83 million, primarily attributable to a revised estimate of interest on income taxes payable. The increase is also due to the impact of additional borrowings and higher interest rates on those borrowings.

Income tax expense decreased 23% to $196 million, primarily reflecting the absence of deferred income taxes recorded in accordance with EITF 93-17 in the first quarter of 2006, associated with the pending sale of Peoples and Hope.

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Segment Results of Operations

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. Presented below is a summary of contributions by operating segments to net income for the quarter ended March 31, 2007 and 2006:

First Quarter	2007			2006			$ Change
(millions)
Delivery	$	134		$	85		$	49
Energy		89			88			1
E&P		113			213			(100	)
Primary operating segments		336			386			(50	)
Corporate		(23	)		(185	)		162
Consolidated	$	313		$	201		$	112

Delivery

Presented below are operating statistics related to our Delivery operations:

	First Quarter
	2007	2006	% Change
Gas throughput (bcf):
Gas sales	46	50	(8	)%
Gas transportation	107	87	23
Heating degree days (gas service area)(1)	3,015	2,580	17
Average gas delivery customer accounts(2):
Gas sales	784	1,004	(22	)
Gas transportation	914	697	31
Average retail energy marketing customer accounts(2)	1,490	1,179	26

bcf = billion cubic feet

(1) Heating degree days (HDDs) are units measuring the extent to which the average daily temperature is less than 65 degrees. HDDs are calculated as the difference between the average temperature for each day and 65 degrees.

(2) Period average, in thousands.

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

	First Quarter 2007 vs. 2006 Increase (Decrease)
(millions)
Retail energy marketing operations(1)	$	26
Regulated gas sales—weather		12
Salaries, wages and benefits expense(2)		3
Depreciation, depletion and amortization expense		3
Other		5
Change in net income contribution	$	49

(1) Higher margins largely attributable to an increase in the number of gas customers and favorable changes in electric prices.

(2) Primarily reflects a decrease in other postretirement benefits expense, as a result of an increase in the associated discount rate.

Energy

Presented below are operating statistics related to our Energy operations:

	First Quarter
	2007	2006	% Change
Gas transportation throughput (bcf)	278	234	19	%

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

	First Quarter 2007 vs. 2006 Increase (Decrease)
(millions)
Gas transmission(1)	$	16
Producer services(2)		(10	)
Other		(5	)
Change in net income contribution	$	1

(1) Primarily due to lower fuel costs resulting from reduced gas usage and lower gas prices, and higher margins from extracted products largely resulting from lower gas prices associated with gas replacement costs.

(2) Decreased margins related to price risk management and gas aggregation activities as a result of reduced market volatility as compared to the post-2005 hurricane market conditions in 2006.

E&P

Presented below are operating statistics related to our E&P operations:

	First Quarter
	2007		2006		% Change
Gas production (bcf)		65.2		60.9	7	%
Oil production (million bbls)		5.2		5.7	(9	)
Average realized prices without hedging results:
Gas (per mcf)(1)	$	6.63	$	8.10	(18	)
Oil (per bbl)		46.90		53.90	(13	)
Average realized prices with hedging results:
Gas (per mcf)(1)	$	5.90	$	5.43	9
Oil (per bbl)		34.99		38.56	(9	)
DD&A (unit of production rate per mcfe)	$	2.02	$	1.76	15

bbl(s) = barrel(s)

mcf = thousand cubic feet

mcfe = thousand cubic feet equivalent

(1) Excludes $23 million and $49 million of revenue recognized for the three months ended March 31, 2007 and 2006, 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, 2006.

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

	First Quarter 2007 vs. 2006 Increase (Decrease)
(millions)
Operations and maintenance(1)	$	(75	)
Depreciation, depletion and amortization expense		(18	)
Gas and oil—production(2)		(12	)
Interest expense		(8	)
Gas and oil—prices		3
Other(3)		10
Change in net income contribution	$	(100	)

(1) Higher operations and maintenance expenses, primarily reflecting the absence of a 2006 benefit from favorable changes in the fair value of certain gas and oil hedges that were de-designated following the 2005 hurricanes.

(2) Represents a decrease in oil production primarily attributable to the deepwater Gulf of Mexico Green Canyon, Triton and Goldfinger projects and also reduced natural gas deliveries and associated revenues recognized under VPP agreements. These decreases were partially offset by increased gas production from deepwater and Permian basin locations.

(3) Primarily reflects a decrease in tax expense due to an unfavorable adjustment in 2006 resulting from revisions to estimated state income tax apportionment percentages on accumulated deferred income taxes.

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Included below are the volumes and weighted-average prices associated with hedges in place as of March 31, 2007 by applicable time period:

	Natural Gas			Oil
Year	Hedged Production (bcf)	Average Hedge Price (per mcf)		Hedged Production (million bbls)	Average Hedge Price (per bbl)
2007	155.9	$	5.98	7.5	$	33.41
2008	151.2		8.26	5.0		49.36
2009	25.5		8.09	0.3		75.36

Corporate

Presented below are the Corporate segment’s after-tax results:

	First Quarter
	2007			2006			$ Change
(millions)
Specific items attributable to operating segments	$	(21	)	$	(106	)	$	85
Other corporate operations		(2	)		(79	)		77
Total net expense	$	(23	)	$	(185	)	$	162

Specific Items Attributable to Operating Segments

Corporate includes specific items attributable to our primary operating segments that have been excluded from the profit measures evaluated by management, either in assessing segment performance or allocating resources among segments. See Note 18 to our Consolidated Financial Statements for a discussion of these items.

Other Corporate Operations

We reported net expenses of $2 million in 2007 associated with other corporate operations, as compared to net expenses of $79 million in 2006, primarily reflecting the absence of tax adjustments recorded in 2006 as a result of the pending sale of Peoples and Hope. In 2006, we recognized $107 million of deferred tax liabilities, in accordance with EITF 93-17. The recognition of these liabilities in 2006 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 that is expected to be generated from the sale.

Credit Risk

Our exposure to potential credit risk results primarily from our sales of gas and oil production, extracted products and energy marketing, including our hedging activities. Presented below is a summary of our gross credit exposure as of March 31, 2007. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. We held no collateral for these transactions at March 31, 2007.

	Gross Credit Exposure
(millions)
Investment grade(1)	$	277
Non-investment grade(2)		12
No external ratings:
Internally rated—investment grade(3)		18
Internally rated—non-investment grade(4)		71
Total	$	378

(1) Designations as investment grade are based on minimum credit ratings assigned by Moody’s Investors Service and Standard & Poor’s Ratings Services. The five largest counterparty exposures, combined, for this category represented approximately 34% of the total net credit exposure.

(2) The five largest counterparty exposures, combined, for this category represented approximately 6% of the total net credit exposure.

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

(4) The five largest counterparty exposures, combined, for this category represented approximately 12% of the total net credit exposure.

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Other Matters

Regulatory Approval of Sale of Peoples and Hope

In March 2006, Peoples and Equitable Resources, Inc. (Equitable) filed a joint petition with the Pennsylvania Public Utility Commission (Pennsylvania 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 (West Virginia Commission) approval of the purchase by Equitable of all of the stock of Hope. In April 2007, the Pennsylvania Commission approved a joint settlement approving the sale in Pennsylvania. Following the approval of the sale of Peoples by the Pennsylvania Commission, the Federal Trade Commission (FTC) filed an action in federal court seeking to block the transaction. A hearing on the FTC’s request for an injunction is scheduled for early June. Dominion and Equitable have asked the court to dismiss the FTC’s complaint and a ruling on this motion to dismiss is expected in early May 2007. The West Virginia Commission has scheduled hearings in May 2007 related to the sale of Hope to Equitable.

Possible Disposition of E&P Business

In November 2006, Dominion announced its decision to pursue a sale of substantially all of our natural gas and oil E&P operations and assets, with the exception of those located in the Appalachian Basin. At December 31, 2006, our natural gas and oil assets — excluding the Appalachian Basin — included about 4.7 trillion cubic feet of proved reserves. The Appalachian assets that we would retain constitute approximately 17% of our total proved reserves at December 31, 2006.

In April 2007, Dominion entered into an agreement with Eni Petroleum to sell our offshore E&P operations for approximately $4.76 billion. The transaction is expected to close by early July 2007, subject to customary closing conditions and adjustments. Our offshore operations include approximately 967 bcfe of proved natural gas and oil reserves in the outer continental shelf and deepwater areas of the Gulf of Mexico at December 31, 2006. Of this total, approximately 961 bcfe are being sold to Eni Petroleum. The effective date for the sale is June 30, 2007. Eni Petroleum’s obligations under the agreement are guaranteed by its parent company, Eni S.p.A. Remaining offshore E&P operations are expected to be disposed of in a separate transaction by early July 2007.

Dominion continues to pursue the potential disposition of our U.S. onshore E&P operations, excluding those in the Appalachian Basin. Net cash proceeds from this disposition and any future dispositions will be used to reduce debt, acquire assets related to our remaining businesses and for other corporate purposes, including the payment of dividends to Dominion.

The offshore disposition will result in an initial pre-tax charge of approximately $370 million, which will be reported in second quarter 2007 earnings. This reflects the discontinuance of hedge accounting for certain cash flow hedges related to our offshore E&P operations since it became probable that the forecasted sales of gas and oil will not occur. In connection with the discontinuance of hedge accounting for these contracts, we will reclassify approximately $370 million of pre-tax losses from AOCI to earnings. We have entered into offsetting positions for these gas and oil derivatives that will minimize the volatility that would have resulted from these contracts being marked to market through earnings. We expect that this charge will be more than offset by the gain we ultimately expect to recognize on the disposition.

In addition to this initial charge, we anticipate recording additional charges related to the disposition plan that are not currently estimable. These charges will include cash expenditures for transaction costs, including employee-related, legal and other costs.

PAGE 28

Cove Point Expansion

In June 2006, the Federal Energy Regulatory Commission (FERC) approved our plans to expand our Cove Point LNG terminal including the installation of two LNG storage tanks, each capable of storing 160 thousand cubic meters of LNG, and expand the send-out capacity of our Cove Point pipeline to approximately 1.8 million dekatherms per day. FERC also approved our plans to expand our DTI facilities by building 81 miles of pipeline and two compressor stations in central Pennsylvania. Statoil ASA has committed to all of the incremental terminal, transportation and storage capacity of the expansion for a term of 20 years. Expansion construction started in August 2006, and is expected to be completed in the fourth quarter of 2008.

Environmental Matters

In April 2007 the U.S. Supreme Court ruled that the Environmental Protection Agency (EPA) has the authority to regulate greenhouse gas emissions under the Clean Air Act which could result in future EPA action. Although we expect legislative or regulatory action on the regulation of greenhouse gas emissions in the future, the outcome in terms of specific requirements and timing is uncertain, and we cannot predict the financial impact on our operations at this time.

ITEM 4. CONTROLS AND PROCEDURES

Senior management, including 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.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to 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 these 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 filed a joint petition with the Pennsylvania 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 Commission approval of the purchase by Equitable of all of the stock of Hope. In April 2007, the Pennsylvania Commission approved a joint settlement approving the sale in Pennsylvania. Following the approval of the sale of Peoples by the Pennsylvania Commission, the FTC filed an action in federal court seeking to block the transaction. A hearing on the FTC’s request for an injunction is scheduled for early June. Dominion and Equitable have asked the court to dismiss the FTC’s complaint and a ruling on this motion to dismiss is expected in early May 2007. The West Virginia Commission has scheduled hearings in May 2007 related to the sale of Hope to Equitable.

In July 1997, Jack Grynberg brought suit against CNG Producing Company, predecessor to DEPI, and several of its affiliates (there are 73 defendants in this case). The suit seeks damages for alleged fraudulent mis-measurement of gas volumes and underreporting of gas royalties from gas production taken from federal leases. The suit was consolidated with approximately 360 other cases in the U.S. District Court for the District of Wyoming. Parts of Mr. Grynberg’s claims were dismissed on the basis that they overlapped with Mr. Wright’s claims, which are noted below. Mr. Grynberg has filed an appeal. In October 2006, Judge Downes issued an order dismissing all claims against DEPI and its affiliates on the jurisdictional grounds that Mr. Grynberg has failed to meet his burden to prove he is the “original source” of the claims being asserted under the False Claims Act. Mr. Grynberg has appealed this order.

In April 1998, Harrold E. (Gene) Wright filed suit against DEPI (formerly known as CNG Producing Company), a subsidiary of CNG, and numerous other companies under the False Claims Act. Mr. Wright alleged various fraudulent valuation practices in the payment of royalties due under federal oil and gas leases. Shortly after filing, this case was consolidated under the Federal Multidistrict Litigation rules with the Grynberg case noted above. A substantial portion of the claim against us was resolved by settlement in late 2002. The case was remanded back to the U.S. District Court for the Eastern District of Texas, which denied our motion to dismiss on jurisdictional grounds in January 2005. Discovery in this matter is currently underway. On February 28, 2007, the Judge issued an order providing that trials will occur in phases on 25% of each defendant’s leases to be selected by the opposing party by July 1, 2007. The Phase I trial (currently involving another defendant) will commence in August 2008. A Phase II trial will occur in February 2009 against two defendants selected by the opposing party by September 14, 2007, with subsequent phases of trials occurring against other defendants in the future with up to two defendants at each future trial.

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

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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, 2006, which factors should be taken into consideration when reviewing the information contained in this report. 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, seeForward-Looking Statements in MD&A.

ITEM 5. OTHER INFORMATION

The following items are reported below in lieu of on a Form 8-K. Each of these events has occurred within four business days preceding the date of this report.

Entry into a Material Definitive Agreement (Form 8-K Item 1.01)

In April 2007, Dominion entered into an agreement with Eni Petroleum to sell our offshore E&P operations for approximately $4.76 billion. The transaction is expected to close by early July 2007, subject to customary closing conditions and adjustments. Our offshore operations include approximately 967 bcfe of proved natural gas and oil reserves in the outer continental shelf and deepwater areas of the Gulf of Mexico at December 31, 2006. Of this total, approximately 961 bcfe are being sold to Eni Petroleum. The effective date for the sale is June 30, 2007. Eni Petroleum’s obligations under the agreement are guaranteed by its parent company, Eni S.p.A. A copy of the Agreement is filed herewith as Exhibit 10.1. Remaining offshore E&P operations are expected to be disposed of in a separate transaction by early July 2007.

Dominion continues to pursue the potential disposition of our U.S. onshore E&P operations, excluding those in the Appalachian Basin. Net cash proceeds from this disposition and any future dispositions will be used to reduce debt, acquire assets related to our remaining businesses and for other corporate purposes, including the payment of dividends to Dominion.

Costs Associated with Exit or Disposal Activities (Form 8-K Item 2.05)

The offshore disposition will result in an initial pre-tax charge of approximately $370 million, which will be reported in second quarter 2007 earnings. This reflects the discontinuance of hedge accounting for certain cash flow hedges related to our offshore E&P operations since it became probable that the forecasted sales of gas and oil will not occur. In connection with the discontinuance of hedge accounting for these contracts, we will reclassify approximately $370 million of pre-tax losses from AOCI to earnings. We have entered into offsetting positions for these gas and oil derivatives that will minimize the volatility that would have resulted from these contracts being marked to market through earnings. We expect that this charge will be more than offset by the gain we ultimately expect to recognize on the disposition.

In addition to this initial charge, we anticipate recording additional charges related to the disposition plan that are not currently estimable. These charges will include cash expenditures for transaction costs, including employee-related, legal and other costs.

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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	Offshore Package Purchase Agreement Between Dominion Exploration & Production, Inc. as Seller and ENI Petroleum Co., Inc. as Purchaser dated as of April 27, 2007 (filed herewith).
12	Ratio of earnings to fixed charges (filed herewith).
31.1	Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2	Certification by Registrant’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32	Certification to the Securities and Exchange Commission by Registrant’s Chief Executive Officer and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
99	Condensed consolidated earnings statements (unaudited) (filed herewith).

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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
May 2, 2007	/s/ Steven A. Rogers
	Steven A. Rogers
	Senior Vice President and Chief Accounting Officer
	(Principal Accounting Officer)

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