SECURITIES AND EXCHANGE COMMISSION

10-Q 1 cngfinal.htm CONSOLIDATED NATURAL GAS COMPANY'S 2ND QUARTER 10- SECURITIES AND EXCHANGE COMMISSION SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

___________________

FORM 10-Q

___________

(Mark One)

X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2001

or

____ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____ to ____

Commission File Number 1-3196

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

Delaware
(State or other jurisdiction of incorporation or organization)

54-1966737
(I.R.S. Employer Identification No.)

120 Tredegar Street
Richmond, Virginia
(Address of principal executive offices)

23219
(Zip Code)

(804) 819-2000
(Registrant's telephone number)

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

As of July 31, 2001, there were issued and outstanding 100 shares of the registrant's common stock, without par value, all of which were held, beneficially and of record, by Dominion Resources, Inc.

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

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CONSOLIDATED NATURAL GAS COMPANY

INDEX

		Page Number
PART I. Financial Information
Item 1.	Consolidated Financial Statements
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2001 and 2000	3
	Consolidated Balance Sheets - June 30, 2001 and December 31, 2000	4-5
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2001 and 2000	6
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2001 and 2000	7
	Notes to Consolidated Financial Statements	8-14
Item 2.	Management's Discussion and Analysis of Results of Operations	15-19
	PART II. Other Information
Item 1.	Legal Proceedings	19
Item 5.	Other Information	19
Item 6.	Exhibits and Reports on Form 8-K	20

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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		Six Months Ended
	June 30,		June 30,
	2001	2000	2001	2000
	(Millions)

Operating Revenue	$745	$721	$2,480	$1,890

Operating Expenses
Purchased gas	267	246	1,326	708
Liquids, pipeline capacity and other purchases	69	73	134	167
Restructuring and other merger-related costs	-	32	-	205
Operations and maintenance	140	129	282	282
Depreciation and amortization	93	112	189	210
Other taxes	33	43	91	98
Total expenses	602	635	2,022	1,670

Income from operations	143	86	458	220

Other income (loss):
Loss on net assets held for sale	-	(17)	-	(152)
Other	3	12	21	17
Total other income (loss)	3	(5)	21	(135)

Income before interest and income taxes	146	81	479	85
Interest and related charges	35	39	96	76
Income before income taxes	111	42	383	9
Income tax expense	38	22	131	11
Income (loss) before cumulative effect of changes in accounting principle	73	20	252	(2)
Cumulative effect of changes in accounting principle (net of income taxes)	-	-	(14)	31
Net Income	$ 73	$ 20	$ 238	$ 29

_______________

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

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CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,	December 31,
	2001	2000*
ASSETS	(Millions)

Current Assets
Cash and cash equivalents	$ 77		$ 58
Accounts receivable:
Customers, net	552		712
Other	182		276
Receivables from affiliated companies	23		18
Inventories	79		96
Commodity contract assets	410		264
Unrecovered gas costs	63		264
Broker margin deposits	51		20
Prepayments	107		154
Deferred income taxes	17		-
Other	83		140
Net assets held for sale	64		57
Total current assets	1,708		2,059

Investments	226		196

Property, Plant and Equipment
Property, plant and equipment	9,716		9,336
Less accumulated depreciation and amortization	5,023		4,968
Total property, plant and equipment, net	4,693		4,368

Deferred Charges and Other Assets
Regulatory assets, net	181		176
Prepaid pension cost	486		434
Commodity contract assets	216		28
Other	31		26
Total deferred charges and other assets	914		664

Total assets	$7,541		$7,287

_______________

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

* The Consolidated Balance Sheet at December 31, 2000 has been derived from the audited Consolidated

Financial Statements at that date.

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CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,	December 31,
	2001	2000*
LIABILITIES AND STOCKHOLDER'S EQUITY	(Millions)

Current Liabilities
Short-term debt	$ 527		$1,215
Accounts payable, trade	491		688
Payables to affiliated companies	142		33
Estimated rate contingencies and refunds	43		41
Accrued interest	31		26
Accrued payroll	38		52
Accrued taxes	123		178
Deferred income taxes	-		87
Commodity contract liabilities	259		27
Temporary replacement reserve - gas inventory	63		-
Broker margin liabilities	151		-
Other	203		209
Total current liabilities	2,071		2,556

Long-Term Debt	2,165		1,721

Deferred Credits and Other Liabilities
Deferred income taxes	929		788
Deferred investment tax credits	17		18
Commodity contract liabilities	132		40
Other	131		198
Total deferred credits and other liabilities	1,209		1,044
Total liabilities	5,445		5,321

Commitments and Contingencies (see Note 12)

Common Stockholder's Equity
Common stock, no par value	1,816		1,816
Other paid-in capital	40		40
Retained earnings	171		111
Accumulated other comprehensive income (loss)	69		(1)
Total common stockholder's equity	2,096		1,966

Total liabilities and stockholder's equity	$7,541		$7,287

_______________

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

* The Consolidated Balance Sheet at December 31, 2000 has been derived from the audited Consolidated

Financial Statements at that date.

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CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30,
	2001	2000
	(Millions)

Net Cash Flows From Operating Activities	$1,028		$370

Cash Flows From (Used In) Investing Activities
Plant construction and other property additions	(182)		(221)
Oil and gas properties and equipment	(342)		(141)
Proceeds from dispositions of property, plant and equipment, net	3		10
Cost of other investments	(34)		(8)
Net cash used in investing activities	(555)		(360)

Cash Flows From (Used In) Financing Activities
Issuance of long-term debt	496		-
Repayment of long-term debt	(84)		-
Issuance (repayment) of short-term debt, net	(688)		24
Dividends paid	(178)		(93)
Net cash used in financing activities	(454)		(69)

Increase (decrease) in cash and cash equivalents	19		(59)
Cash and cash equivalents at beginning of period	58		94
Cash and cash equivalents at end of period	$ 77		$ 35

_______________

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

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CONSOLIDATED NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2001	2000	2001	2000
	(Millions)

Net income	$ 73	$20	$238	$29

Other comprehensive income, net of tax:
Adjustment for foreign currency translation	-	-	-	(1)
Amount reclassified from AOCI to net income	-	-	-	3
Cumulative effect of a change in accounting principle
(net of income taxes of $57)	-	-	(105)	-
Unrealized derivative gains - hedging activities	85	-	105	-
Reclassification for derivative losses included in net income	12	-	68	-
Other comprehensive income	97	-	68	2

Comprehensive income	$170	$20	$306	$31

_______________

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

PAGE 8

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Nature of Operations

Consolidated Natural Gas Company is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act). On January 28, 2000, Dominion Resources, Inc. (Dominion) and Consolidated Natural Gas Company (the Company) completed the merger of the Company into a subsidiary (New Company) of Dominion. The name of New Company was changed to Consolidated Natural Gas Company at the time of the merger. To give effect to the continuity of the Company and New Company, the term "Company" as used in this report refers to Consolidated Natural Gas Company both before and after the merger unless the context of a statement requires the use of separate references to each company.

The Company, through its subsidiaries, operates in all phases of the natural gas business, explores for and produces oil and provides a variety of energy marketing services. Its regulated retail gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Its interstate gas transmission pipeline system services each of its distribution subsidiaries, non-affiliated utilities and end use customers in the Midwest, the Mid-Atlantic and the Northeast states. The Company's exploration and production operations are conducted in several of the major gas and oil producing basins in the United States, both onshore and offshore.

The Company evaluates its operations along functional lines rather than legal entities. The principal functional segments include Distribution (representing the retail gas distribution subsidiaries), Transmission (representing the pipeline, storage and by-product operations and the gas and oil production activities of Dominion Transmission, and the activities of the Company's gas marketing subsidiaries, Dominion Field Services and Dominion Retail), and Exploration and Production (representing the exploration and production operations of Dominion Exploration & Production).

Note 2. Significant Accounting Policies

In the opinion of management, the accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly the Company's financial position as of June 30, 2001, the results of operations and comprehensive income for the three and six months ended June 30, 2001 and 2000, and cash flows for the six months ended June 30, 2001 and 2000. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year.

These Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements, and notes thereto, included in the Company's Annual Report on Form 10-K for the year ended December 31, 2000.

The Consolidated Financial Statements represent the accounts of the Company after the elimination of intercompany transactions.

The Consolidated Financial Statements reflect certain estimates and assumptions made by management that 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.

Certain amounts in the 2000 Consolidated Financial Statements have been reclassified to conform to the 2001 presentation.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 3. Recently Issued Accounting Standards

Business Combination and Goodwill

In July 2001, the Financial Accounting Standards Board (FASB) issued Statements of Financial Accounting Standards (SFAS) Nos. 141, Business Combinations, and 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting, thus eliminating the use of the "pooling" method of accounting. For any business combination, which will be accounted for using the purchase method, initiated before July 1, 2001 and completed before January 2002, the provisions of SFAS No. 141 will also apply. Under SFAS No. 142, goodwill is no longer subject to amortization; instead it will be subject to new impairment testing criteria. Other intangible assets will continue to be amortized over their estimated useful lives, although those with indefinite lives are not to be amortized but will be tested at least annually for impairment. The new standards also provide new guidance regarding the identification and recognition of intangible assets, other than goodwill, acquired as part of a business combination. The Company will adopt this standard effective January 1, 2002. At June 30, 2001, the Company had no material amounts of goodwill or intangible assets obtained in business combinations on its books.

Asset Retirement Obligations

In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligation, which provides accounting requirements for the recognition and measurement of liabilities for obligations associated with the retirement of tangible long-lived assets. Under this standard, these liabilities will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities due to the passage of time will be expensed. Although FASB has not yet published the final standard, the Company's preliminary conclusions are based on previously issued exposure drafts and subsequent deliberations. The Company will adopt this standard effective January 1, 2003. Upon the adoption of this new standard, the Company will discontinue its practice of accruing, as part of depreciation expense, amounts associated with the future costs of removal for its gas utility and oil and gas exploration and production. However, the Company may continue its practice of accruing for future costs of removal subject to cost of service utility rate regulation even when an asset removal obligation does not exist but would do so through the recognition of regulatory assets and liabilities, as appropriate.

Note 4. Derivatives and Hedge Accounting

Adoption of Statement of Financial Accounting Standards (SFAS) No. 133

The Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, on January 1, 2001. The Company recorded an after-tax loss of $14 million (net of income taxes of $8 million) during the quarter ended March 31, 2001, representing the cumulative effect of adopting SFAS No. 133 in its Consolidated Statement of Income. The Company also recorded a net after-tax charge to accumulated other comprehensive income (AOCI) of $105 million (net of income taxes of $57 million) in the first quarter of 2001 in connection with the initial adoption of SFAS No. 133. The Company expects to reclassify approximately $117 million of this amount to earnings during the year ending December 31, 2001. The actual amounts that will be reclassified to earnings over the twelve months subsequent to initial adoption will vary from this amount as a result of changes in market conditions. The effect of the charges being 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.

Risk Management Policy

The Company uses derivatives to manage the commodity and financial market risks of its business operations. The Company manages the price risk associated with purchases and sales of natural gas and oil by utilizing derivative commodity instruments including futures, forwards, options, swaps and collars. The Company manages its interest rate risk exposure, in part, by entering into interest rate swap transactions.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

The Company designates a substantial portion of its derivatives as fair value or cash flow hedges. A significant portion of the Company's hedge strategies represents cash flow hedges of the variable price risk associated with purchases and sales of natural gas, oil and other commodities using derivative instruments discussed in the preceding paragraph. However, the Company also engages in fair value hedges by utilizing natural gas swaps, futures and options to mitigate the fixed price exposure inherent in the Company's firm commitments and interest rate swaps to hedge its exposure to fixed interest rates on certain long-term debt. Certain of the Company's derivatives, which management believes are economic hedges and mitigate exposure to fluctuations in commodity prices, are not designated as hedges for accounting purposes.

Accounting Policy

Under SFAS No. 133, derivatives are recognized on the Consolidated Balance Sheet at fair value, unless a scope exception is available under the standard. Commodity contracts representing unrealized gain positions are reported as commodity contract assets; commodity contracts representing unrealized losses are reported as commodity contract liabilities. In addition, purchased options and options sold are reported as commodity contract assets and commodity contract liabilities, respectively, at estimated market value until exercise or expiration. Cash flows from derivative instruments are presented in net cash flow from operating activities.

For all derivatives designated as a hedge, the Company formally documents the relationship between the hedging instrument and the hedged item, as well as the risk management objective and strategy for the use of the hedging instrument. The Company assesses, both at the inception of the hedge and on an ongoing basis, whether the hedge relationship between the derivative and the hedged item is highly effective in offsetting changes in fair value or cash flows. Any change in fair value of the derivative resulting from ineffectiveness, as defined by SFAS No. 133, is recognized currently in earnings. Further, for derivatives that have ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively.

For fair value hedge transactions in which the Company is hedging changes in the fair value of an asset, liability, or firm commitment, changes in the fair value of the derivative will generally be offset in the consolidated statement of income by changes in the hedged item's fair value. For cash flow hedge transactions in which the Company is hedging the variability of cash flows related to a variable-priced asset, liability, commitment, or forecasted transaction, changes in the fair value of the derivative are reported in AOCI. The gains and losses on the derivatives that are reported in AOCI are reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portion of the change in fair value of derivatives and the change in fair value of derivatives not designated as hedges for accounting purposes are recognized in current-period earnings. For options designated either as fair value or cash flow hedges, changes in the time value are excluded from the measurement of hedge effectiveness and are, therefore, recorded in earnings.

Gains and losses on derivatives designated as hedges, when recognized, are included in the operating revenue and income, expenses and interest and related charges in the consolidated statements of income. Specific line item classification is determined based on the nature of the risk underlying individual hedge strategies. Changes in the fair value of derivatives not designated as hedges, and the portion of hedging derivatives excluded from the measurement of effectiveness are included in operations and maintenance expense in the consolidated statements of income.

Derivatives and Hedge Accounting Results

For the three and six-month periods ended June 30, 2001, the Company recognized a total pre-tax increase in earnings of approximately $1 million for hedge ineffectiveness. This amount, which relates entirely to fair value hedges, is primarily reported as a reduction to cost of sales in the Consolidated Statements of Income. In addition, the Company recognized a pre-tax decrease to earnings of approximately $1 million during the three month period ended June 30, 2001, representing the change in time value of options not used in the assessment of effectiveness for cash flow hedges. The change in time value of options not used in the assessment of effectiveness for cash flow hedges during the six-month period ended June 30, 2001 was not significant.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Approximately $37 million of net gains in AOCI at June 30, 2001 is expected to be reclassified to earnings within the next twelve-month period. The actual amounts that will be reclassified to earnings over the next twelve months will vary from this amount as a result of changes in market conditions. The effect of the charges being 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. As of June 30, 2001, the Company is hedging its exposure to the variability in future cash flows for forecasted transactions over periods of one to five years.

As a result of the clearance of additional interpretive guidance by the Financial Accounting Standards Board (FASB) during the second quarter, the Company reviewed certain contracts that were determined not to be subject to fair value accounting upon implementation of SFAS No. 133. Based on this review and the new guidance, certain contracts were determined to be subject to fair value accounting under SFAS No. 133. Effective July 1, 2001, these contracts were incorporated as hedging instruments in appropriate cash flow hedging strategies. The effect of implementing these changes will not have a material impact on the Company's financial position, results of operations or cash flows.

Future interpretations of SFAS No. 133 by the FASB or other standard-setting bodies could result in fair value accounting being required for certain contracts that are not currently being subjected to such requirements. Accordingly, such future interpretations may impact the Company's ultimate application of the standard. However, if future changes in the application of SFAS No. 133 should result in additional Company contracts becoming subject to fair value accounting under SFAS No. 133, the Company would pursue hedging strategies to mitigate any potential future volatility in reported earnings.

Note 5. Change in Accounting for Pensions

The Consolidated Financial Statements for the three and six months ended June 30, 2000 have been restated to reflect a change in the method of calculating the market related value of pension plan assets used to determine the expected return on pension plan assets, a component of net periodic pension cost. The new method was adopted in the third quarter of 2000 and effective as of January 1, 2000.

A cumulative effect of a change in accounting principle of $31 million (net of income taxes of $11 million) was included in income for the six months ended June 30, 2000. The overall effect of the change was to increase income before cumulative effect of a change in accounting principle by $5 million for the six months ended June 30, 2000, and to increase net income for the three and six months ended June 30, 2000 by $3 million and $36 million, respectively.

For additional information concerning the cumulative effect of a change in accounting principle for net periodic pension costs, see Note 3 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2000.

Note 6. Merger

On January 28, 2000, Dominion acquired all of the outstanding shares of the Company's common stock for $6.4 billion, consisting of approximately 87 million shares of Dominion common stock valued at $3.5 billion and approximately $2.9 billion in cash. The acquisition was completed by merging the Company into a new subsidiary of Dominion. The name of the new Dominion subsidiary was changed to Consolidated Natural Gas Company at the time of the merger.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 7. Restructuring and Other Merger-Related Activities

Following the January 28, 2000 acquisition by Dominion, Dominion and its subsidiaries implemented a plan to restructure the operations of the combined companies. The restructuring plan included an involuntary severance program, a voluntary early retirement program (ERP) and a transition plan to implement operational changes to provide efficiencies, including the consolidation of post-merger operations and the integration of information technology systems. At December 31, 2000, the Company's restructuring plan was substantially complete.

The Company recorded restructuring and other merger-related costs for the three and six months ended June 30, 2000, as follows:

	Three Months Ended	Six Months Ended
	June 30, 2000
	(Millions)
Commodity contract losses	$ -	$ 55
ERP	36	36
Settlement of certain employment contracts	2	33
Severance liability accrued	(16)	28
Seismic licensing agreements	-	26
Information technology related costs	8	13
Transaction fees	1	10
Other	1	4
Total	$ 32	$205

At June 30, 2001, there remains a severance liability of $7 million that represents remaining amounts payable to employees already terminated and an accrual for estimated payments related to approximately 21 positions not yet eliminated. The change in the liability for severance and related benefit costs is presented below:

	(Millions)
Balance at December 31, 2000	$13
Amounts paid	(6)
Balance at June 30, 2001	$ 7

For additional information on restructuring and other merger-related activities, see Note 6 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2000.

Note 8. Impairment of International Investments

In connection with the Company's decision to end its involvement with international activities, the Company recognized a pre-tax loss of $35 million ($23 million after taxes) in the first quarter of 2000 to write down the carrying amount of CNG International's Australian investments to estimated fair value less cost to sell. In addition, the Company believes it is probable that, as part of a sale, it will be required to make a $100 million equity contribution pursuant to an Equity Contribution Agreement with DBNGP Finance Company LLC. Accordingly, the Company recognized a $100 million ($65 million after taxes) charge in the first quarter of 2000.

On July 7, 2000, Sempra Energy International, a subsidiary of Sempra Energy, agreed to purchase CNG International's Argentine investments for $145 million. Based upon anticipated proceeds from the sale, the carrying amount of these investments was adjusted, resulting in an impairment loss of $17 million ($11 million after taxes) in the second quarter of 2000.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Total impairment loss related to CNG International for the six months ended June 30, 2000 was $152 million ($99 million after taxes).

For additional information on the write-downs, and on the Company's international investments, see Note 7 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2000.

Note 9. Estimated Rate Contingencies and Refunds

Certain increases in prices by the Company and other ratemaking issues are subject to final modification in regulatory proceedings. The related accumulated provisions pertaining to these matters, including interest, were $42 million and $40 million at June 30, 2001 and December 31, 2000, respectively. These provisions are included in the Consolidated Balance Sheet under "Estimated rate contingencies and refunds" along with $1 million for both periods as primarily refunds received from suppliers and refundable to customers under regulatory procedures.

Note 10. Long-Term Debt

During the first quarter of 2001, the Company redeemed the $84 million outstanding of its $150 million, 8.75% Debentures due October 1, 2019.

On April 11, 2001, the Company issued $500 million of 2001 Series A, 6.85% Senior Notes due 2011 (Senior Notes). The Company used the net proceeds from the sale of the Senior Notes for general corporate purposes, including repayment of commercial paper. At June 30, 2001, following the issuance of the Senior Notes, the Company had $1 billion remaining under a shelf registration with the Securities and Exchange Commission.

Note 11. Dividend Restrictions

At December 31, 2000, one of the Company's indentures relating to its long-term debt contained restrictions on dividend payments by the Company. As of that date, $19 million of the Company's consolidated retained earnings was free from such restriction. In March 2001, the Company requested and obtained the consent of bondholders to amend the indenture to eliminate certain provisions of the indenture, including such dividend restrictions. On March 19, 2001, the Company received an order from the Securities and Exchange Commission, under the 1935 Act, approving the amendment of the indenture.

Note 12. Commitments and Contingencies

There have been no significant developments with regard to commitments and contingencies, including environmental matters, as disclosed in Note 19 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2000, nor have any significant new matters arisen during the six months ended June 30, 2001.

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CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 13. Operating Segments

The Company is organized primarily on the basis of products and services sold in the United States. For a detailed description of the Company's operating segments, reference is made to Notes 1 and 22 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2000. In the first quarter of 2001, the Company changed its presentation for the Transmission segment to include the gas and oil production activities of Dominion Transmission, and the activities of Dominion Retail. Prior to 2001, the gas and oil production activities of Dominion Transmission were included in the Exploration and Production segment, and the activities of Dominion Retail were included in Other. As a result of these changes, segment information for the three and six months ended June 30, 2000 has been restated. Corporate and Other include the effects of charges for which the individual segments were not held accountable: 1) the cumulative effect of adopting SFAS No. 133 for the three and six months ended June 30, 2001; 2) the restructuring and other merger-related costs, the cumulative effect of the change in pension accounting and the impairment loss on CNG International's assets for the three and six months ended June 30, 2000; and 3) intersegment eliminations, where applicable.

			Exploration	Corporate
			and	and	Consolidated
(Millions)	Distribution	Transmission	Production	Other	Total

Three Months ended June 30, 2001
External customer revenue	$ 250	$282	$203	$ 10	$ 745
Intersegment revenue	-	25	19	(44)	-
Net income	2	32	46	(7)	73

Three Months ended June 30, 2000
External customer revenue	$ 264	$228	$224	$ 5	$ 721
Intersegment revenue	2	29	11	(42)	-
Net income	-	29	33	(42)	20

Six Months ended June 30, 2001
External customer revenue	$1,190	$873	$405	$ 12	$2,480
Intersegment revenue	1	79	44	(124)	-
Net income	98	95	75	(30)	238

Six Months ended June 30, 2000
External customer revenue	$ 992	$467	$426	$ 5	$1,890
Intersegment revenue	3	73	20	(96)	-
Net income	106	88	59	(224)	29

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CONSOLIDATED NATURAL GAS COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS

Cautionary Statements Regarding Forward-Looking Information

From time to time the Company makes statements concerning its expectations, plans, objectives, future financial performance and other statements that are not historic facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. In some cases, the reader can identify these forward-looking statements by words such as "anticipate", "estimate", "expect", "believe", "could", "plan", "may" or other words with similar meaning.

Forward-looking statements are issued by the Company with full knowledge that risks and uncertainties exist that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ are often presented with forward-looking statements. In addition, other factors could cause actual results to differ materially from those indicated in any forward-looking statement. These include:

Factors affecting operations, such as:

unusual weather conditions;

catastrophic weather-related damage;

unusual maintenance or repairs;

unanticipated changes in gas supply costs or availability constraints;

environmental incidents; and

gas pipeline system costs or availability constraints.

State, federal and international legislative and regulatory developments, including deregulation and restructuring of the gas industry and changes in environmental and other relevant laws and regulations to which the Company is subject;

The effects of competition, including the extent and timing of the entry of additional competitors in the gas market;

The pursuit of potential business strategies, including acquisitions or dispositions of assets;

Regulatory factors such as changes in the policies or procedures that set rates, changes in the ability to recover investments made under traditional regulation through rates, and changes to the frequency and timing of rate increases;

Financial or regulatory accounting principles or policies imposed by governing bodies;

Political and economic conditions and developments in jurisdictions where the Company operates. This would include inflation rates and monetary fluctuations;

Changing market conditions and other factors related to physical and financial energy business activities, including price, basis, credit, liquidity, volatility, capacity, transmission, currency exchange rates, interest rates and warranty risks;

Financial market conditions, including availability and cost of capital, and the ability to obtain financing on favorable terms;

The performance of projects and the success of efforts to invest in and develop new opportunities;

Employee workforce factors, including collective bargaining agreements with union employees.

PAGE 16

CONSOLIDATED NATURAL GAS COMPANY

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

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

Results of Operations

A major portion of the gas sold or transported by the Company's Distribution and Transmission operations is ultimately used for space heating. As a result, earnings are affected by seasonality and changes in the weather. Because most of the Company's operating subsidiaries are subject to price regulation by federal or state commissions, earnings can be affected by regulatory delays when price increases are sought through general rate filings to recover certain higher costs of operation.

Operating Segment Results

This section provides a general discussion of contributions to net income by the Distribution, Transmission and Exploration and Production segments, and certain expenses not allocated to those segments are included in Corporate and Other.

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2001	2000	2001	2000
	(Millions)

Distribution	$ 2	$ -	$ 98	$106
Transmission	32	29	95	88
Exploration and Production	46	33	75	59
Corporate and other	(7)	(42)	(30)	(224)
Total net income	$73	$ 20	$238	$ 29

Distribution Segment

The Company's Distribution segment contributed $2 million to net income in the second quarter of 2001. In the comparable quarter of 2000, the Distribution segment was at a break even level. The operating results for the second quarter for 2001 and 2000 reflect the seasonal nature of space heating business of the Distribution segment. The Distribution segment contributed $98 million to net income for the six months ended June 30, 2001, compared to $106 million for the comparable period in 2000. The quarter and year-to-date comparisons are affected by the absence of Virginia Natural Gas (VNG) from the 2001 results. The Company sold VNG in October 2000 pursuant to conditions set forth by the Virginia State Corporation Commission and the Federal Trade Commission in connection with their approval of the acquisition of the Company by Dominion. Excluding the contribution from VNG, the Company's remaining three gas distribution subsidiaries contributed $2 million to net income in the second quarter of 2000, and $94 million in the first six months of 2000. The increase in net income during the second quarter of 2001 was attributable to the reductions in purchased gas and other taxes, partially offset by increases in operations and maintenance (O&M), and depreciation expenses. The increase in O&M expense was due principally to a $16 million provision in uncollectible customer accounts expense for the second quarter of 2001 ($27 million for the six months ended June 30, 2001). The higher uncollectible customer accounts are primarily the result of the extremely high level of natural gas costs and colder weather experienced during the past winter. The increase in net income in the six months ended June 30, 2001 was due to colder weather in the first quarter, offset partially by higher operating costs, principally in purchased gas.

PAGE 17

CONSOLIDATED NATURAL GAS COMPANY

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

Total Distribution throughput was 53 billion cubic feet (Bcf) and 215 Bcf in the three and six months ended June 30, 2001, respectively, down 20 Bcf and 34 Bcf from the comparable periods in the prior year. However, both the quarter and year-to-date comparisons are affected by the absence of Virginia Natural Gas from the 2001 results. Excluding VNG, total throughput was down 14 Bcf in both the second quarter and first six months of 2001. The decreased throughput volumes reflect lower industrial deliveries and warmer weather experienced in the second quarter of 2001 as compared with 2000. The decrease in industrial deliveries were the result of a lower level of industrial activity due to high gas prices, and the bankruptcy reorganization by a major steel producing customer. Residential and commercial gas sales, as well as volumes transported, by the three distribution subsidiaries have declined in 2001. The volumes transported for these customers declined due to milder weather in the second quarter while the decrease in gas sales reflects the switch from sales to transport service for customers participating in the Ohio Energy Choice program. In the fall of 2000, the Energy Choice program was expanded to all 1.2 million customers in the Company's Ohio service territory.

Transmission Segment

The Company's Transmission segment contributed $32 million and $95 million to net income for the three and six months ended June 30, 2001, respectively, as compared to $29 million and $88 million in the comparable periods of 2000. The results in 2001 benefited from both higher nonregulated gas sales and natural gas by-product revenue. The increased nonregulated gas sales revenue reflects the transfer of certain gas marketing operations from another Dominion subsidiary in May of 2000, as well as higher gas prices and continued growth in the segment's nonregulated marketing businesses. Natural gas by-product revenue was higher, reflecting increased volumes for all products and higher prices for both propane and butane. Transmission throughput decreased by 18 Bcf and 41 Bcf for the three and six months ended June 30, 2001, respectively, as compared to the comparable periods in 2000.

Exploration and Production Segment

The Company's Exploration and Production segment contributed $46 million and $75 million to net income for the three and six months ended June 30, 2001, respectively, as compared to $33 million and $59 million in the comparable periods last year. The increase resulted primarily from higher oil and gas prices, offset in part by lower production volumes. The lower production volumes in the second quarter of 2001 also resulted in decreased depreciation and amortization expense in both 2001 periods. Revenues from the Company's brokered oil program were lower in both 2001 periods, as compared to 2000, as the result of lower volumes. However, the lower brokered oil revenues were offset by a decrease in purchased liquids expense.

The Company's average gas wellhead price increased $.75 to $3.71 per thousand cubic feet (Mcf) in the second quarter of 2001 and $.75 to $3.51 per Mcf for the six months ended June 30, 2001 over the comparable periods in 2000. Gas production was down from the comparable periods in 2000 due primarily to natural production declines at older properties and a scheduled production outage at the Popeye field in the Gulf of Mexico. The Company's average oil price was $22.95 and $23.42 per barrel for the three and six months ended June 30, 2001, respectively, compared to $19.21 and $16.92 per barrel in the prior year periods. Oil production was down as compared to 2000 levels. The lower oil production volumes reflected natural production declines at the Neptune deepwater field and other older properties, and the sale of the Company's Canadian oil producing properties to another subsidiary of Dominion effective January 1, 2001.

PAGE 18

CONSOLIDATED NATURAL GAS COMPANY

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

Corporate and Other

The activities of Dominion Products and Services, CNG International and other minor subsidiaries are included in the Corporate and Other segment. Corporate and Other also include certain expenses not allocated to the individual operating segments: 1) the cumulative effect of adopting Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133) for the three and six months ended June 30, 2001; 2) the restructuring and other merger-related costs, the cumulative effect of the change in pension accounting and the impairment loss on CNG International's assets for the three and six months ended June 30, 2000; and 3) intersegment eliminations, where applicable.

Future Issues Other Other Information

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by and subsequent to these financial statements. It is recommended that this section be read in connection with MD&A included in the Company's Annual Report on Form 10-K for the year ended December 31, 2000.

Derivatives and Hedge Accounting

Future interpretations of SFAS No. 133 by the Financial Accounting Standards Board or other standard-setting bodies could result in fair value accounting being required for certain contracts that are not currently subject to such requirements. If conclusions concerning the applicability of SFAS No. 133 to the Company's existing contracts are adversely affected by any future interpretations of the standard, certain of the existing contracts may become subject to fair value accounting. In that event, if the Company cannot document cash flow or fair value hedging strategies which would utilize such contracts as hedging instruments, the application of fair value accounting to any contract could result in volatility in reported earnings. Such volatility would result from unrealized gains or losses attributable to changes in the contracts' fair value during a particular reporting period. These unrealized gains and losses may not be indicative of actual cash transactions or profitability that would ultimately be realized over the life of a contract. Thus, the Company believes any increased volatility in earnings attributable to fair value accounting in these circumstances would be of a non-cash nature and would not be accompanied by corresponding volatility in cash flows or a change in liquidity.

Proposed FERC Rate Settlement - Gas Transmission

On June 22, 2001, Dominion Transmission (DTI) and its customers filed a broadly-supported settlement with the Federal Energy Regulatory Commission (FERC), regarding DTI's September 2000 transportation cost rate adjustment. The filed settlement would resolve disputes over DTI's proposal to recover $65 million in system gas requirement costs from its customers, including the costs of gas used as fuel in operating the system, and normal gas losses from pipeline facilities and underground storage formations. DTI has traditionally tracked these costs, billing customers for any under-collections of retained fuel, and refunding any over-collections. In addition, if the settlement is approved as filed, DTI will retain certain fixed percentages of gas receipts and will assume both the risk of under-collections and the reward of any excess gas retained. The settlement would also resolve all remaining transportation and storage customer responsibility for fuel and shrinkage costs for DTI's Hastings gas processing facility. Under the filed settlement, no party can seek a change to the fuel retention mechanism, or the fuel retention percentages, for effectiveness prior to July 1, 2003. DTI will also extend an existing moratorium, so that it cannot make a general rate filing effective prior to July 1, 2003. DTI does not anticipate the FERC ruling on the filed settlement prior to September 2001. The Company does not expect any material impact on its results of operations, financial position or cash flows from implementation of the settlement. However, under the settlement mechanism, management of system gas requirements in the future will have a direct effect on the Company's earnings.

PAGE 19

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

Recently Issued Accounting Standards
Business Combination and Goodwill

Asset Retirement Obligations

PAGE 20

CONSOLIDATED NATURAL GAS COMPANY

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, the Company and its subsidiaries 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. From time to time, there also may be administrative proceedings on these matters pending. In addition, in the normal course of business, the Company and its subsidiaries are involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on the Company's financial position, liquidity or results of operations. See Item 5 - Other Information for discussion on various regulatory proceedings to which we are a party.

As previously reported in the Company's Annual Report on Form 10-K for the year ended December 31, 2000, Jack Grynberg has brought suit against a major part of the gas industry, including Consolidated Natural Gas Company (CNG) and several of its subsidiaries. The suit alleges fraudulent mismeasurement of gas volumes and underreporting of gas royalties from gas production taken from federal leases. In April 2001, the U.S. District Court issued an order denying a motion to dismiss. CNG and other defendents in this matter have filed a motion to certify the case for appeal.

ITEM 5. OTHER INFORMATION

The matters discussed in this Item may contain "forward looking statements" as described in the introductory paragraphs of Part I, Item 2 of this Form 10-Q. See Cautionary Statements Regarding Forward-Looking Information in Part I, Item 2, for discussion of various risks and uncertainties that may affect the future of CNG.

Regulatory

In June 2001, Dominion East Ohio filed a gas cost recovery filing (GCR) with the Public Utilities Commission of Ohio. Under the GCR proposal, sales customers would pay 29% less for natural gas than they now do under a new rate that will be frozen through April 29, 2002. Dominion East Ohio expects to lock in current lower market prices with a combination of longer-term gas purchase contracts and other hedging techniques, to stabilize winter gas costs for its customers through the coming winter period. Dominion East Ohio does not earn a profit on the gas cost recovery, which represents the cost of securing natural gas supplies; therefore, the Company does not expect to experience any financial statement impact from the filed proposal.

Dominion Peoples lowered its rates about 8 percent, effective July 1, 2001. The change reflects a reduction in the natural gas cost recovery portion of its rates from $9.99 to $8.70 per thousand cubic feet. The decrease will not affect customers who buy gas from another supplier as part of Dominion Peoples' Energy Choice program. The lower rate is attributable to the price of natural gas dropping on the national market after record high prices over the past 18 months.

In June 2001, Dominion Transmission (DTI) and its customers filed a rate settlement with the Federal Energy Regulatory Commission (FERC). The filed settlement would resolve disputes over proposed gas cost recoveries from customers, including the costs of gas used as fuel in operating the system, and normal gas losses from pipeline facilities and underground storage formations. If the settlement is approved as filed, DTI will retain certain fixed percentages of gas receipts and will assume both the risk of under-collections and the reward of any excess gas retained. See Future Issues -Dominion Transmission in Management's Discussion & Analysis for additional information.

PAGE 21

CONSOLIDATED NATURAL GAS COMPANY

PART II - OTHER INFORMATION
(Continued)

In May 2001, FERC also approved DTI's Order No. 637 settlement. The settlement enables DTI to offer several customer-driven enhancements to its services. FERC also revised its gas pipeline regulations under this order to improve the competitiveness and efficiency of the interstate pipeline grid. Order No. 637 requires all pipelines to comply with new policies on various key issues, procedures for customers to schedule gas deliveries, provisions for penalties if customers do not comply with service agreements, tools to correct imbalances that occur when customers take more or less gas than requested, and "segmentation," which gives shippers more flexibility to move gas using pipeline service entitlements.

Labor Relations

Negotiators for the Natural Gas Workers Union, SEIU Local 555 (Local 555) and Dominion East Ohio reached a tentative agreement for a new five-year contract on July 16, 2001. The agreement has been subsequently approved by Local 555 membership.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits:

3.1

Certificate of Incorporation of Consolidated Natural Gas Company (Exhibit (3A)(i) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference).

3.2

Certificate of Amendment of Certificate of Incorporation, dated January 28, 2000 (Exhibit (3A)(ii) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference).

3.3

Bylaws as in effect on December 15, 2000 (Exhibit 3B to Form 10-K for the fiscal year ended December 31, 2000, File No. 1-3196, incorporated by reference).

10.1

Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 1, 2001 (filed herewith).

10.2

Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 1, 2001 (filed herewith).

(b) Reports on Form 8-K:

There have been no Forms 8-K filed which were not previously reported.

SIGNATURE

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

	CONSOLIDATED NATURAL GAS COMPANY Registrant

August 3, 2001	/s/ Steven A. Rogers
	Steven A. Rogers Vice President and Controller (Principal Accounting Officer)

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

3.1	Certificate of Incorporation of Consolidated Natural Gas Company (Exhibit (3A)(i) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference).

3.2	Certificate of Amendment of Certificate of Incorporation, dated January 28, 2000 (Exhibit (3A)(ii) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference).

3.3	Bylaws as in effect on December 15, 2000 (Exhibit 3B to Form 10-K for the fiscal year ended December 31, 2000, File No. 1-3196, incorporated by reference).

10.1	Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 1, 2001 (filed herewith).

10.2	Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 1, 2001 (filed herewith).