___________________

Commission File Number 1-3196

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 October 31, 2002, 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.

PAGE 3

________________

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

PAGE 4

________________

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

*The Consolidated Balance Sheet at December 31, 2001 has been derived from the audited Consolidated Financial Statements at that date.

PAGE 5

________________

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

*The Consolidated Balance Sheet at December 31, 2001 has been derived from the audited Consolidated
Financial Statements at that date.

**Debt securities issued by Consolidated Natural Gas Company constitute 100 percent of the Trust's assets.

PAGE 6

________________

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

PAGE 7

Consolidated Natural Gas Company (the Company), a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act), is a wholly owned subsidiary of Dominion Resources, Inc. (Dominion). The Company, through its subsidiaries, operates in all phases of the natural gas business, explores for and produces gas and oil and provides a variety of energy marketing services. Its regulated 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-users in the Midwest, the Mid-Atlantic States and the Northeast. The Company's exploration and production operations are located in several major gas and oil producing basins in the United States, both onshore and offshore. The Company also provides a variety o f energy marketing services and holds an equity investment in energy-related activities in Australia that is classified as held for sale. See Note 8 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001 for additional information.

The Company manages its daily operations through three primary operating segments: Delivery, Energy, and Exploration and Production. In addition, the Company also reports its Corporate and Other operations as an operating segment. Assets remain wholly owned by its legal subsidiaries. For a detailed description of the Company's operating segments, see Note 16.

Within this document, "the Company" is used and, depending on the context of its use, may represent any of the following: the legal entity, Consolidated Natural Gas Company, one of the Consolidated Natural Gas Company's consolidated subsidiaries or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries.

As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), the accompanying unaudited consolidated financial statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles). These unaudited consolidated financial statements should be read in conjunction with the Consolidated Financial Statements and Notes in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

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 September 30, 2002, and its results of operations for the three-month and nine-month periods and cash flows for the nine-month periods ended September 30, 2002 and 2001.

The consolidated financial statements represent the accounts of the Company and its subsidiaries, with all significant intercompany transactions eliminated in consolidation. The Company follows the equity method of accounting for investments in partnerships and corporate joint ventures when the Company is able to influence the financial and operating policies of the investee. For all other investments, the cost method is applied.

The accompanying unaudited consolidated financial statements reflect certain estimates and assumptions made by management in accordance with generally accepted accounting principles. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses for the periods presented. Actual results may differ from those estimates.

PAGE 8

CONSOLIDATED NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)

The Company reports certain contracts and instruments at fair value in accordance with generally accepted accounting principles. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, the Company estimates fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value. See Note 2 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001 for a more detailed discussion of the Company's estimation techniques.

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

Certain amounts in the 2001 consolidated financial statements have been reclassified to conform to the 2002 presentation.

In 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the 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 an operating expense. The Company has identified certain retirement obligations that will be subject to the standard and will adopt the standard effective January 1, 2003. These obligations are associated with the dismantlement and restoration activities for its gas and oil wells and platforms, the removal of certain facilities, and the abandonment of certain natural gas pipelines. At this time, management anticipates no adverse effect on the Company's 2003 net income or its financial position as a result of adopting the standard. Management's expectations are based on its interpretation of the standard and determination of underlying assumptions, such as discount rates and engineering estimates of the future cost and timing of removal activities to be performed, as of the date of this quarterly report. Further refinement of engineering estimates or changes in assumptions underlying the required calculations may be deemed appropriate before the standard is implemented. For more discussion, see Note 4 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

Note 4.     Goodwill and Intangible Assets

In 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 prohibits the amortization of goodwill and intangible assets with indefinite useful lives. SFAS No. 142 also requires that these assets be reviewed for impairment at least annually. Intangible assets with finite lives will continue to be amortized over their estimated useful lives.

PAGE 9

The Company adopted SFAS No. 142 on January 1, 2002. The Company is required to test its goodwill for impairment using a two-step process described in SFAS No. 142 on an annual basis or whenever events or circumstances indicate that the fair value of the Company's reporting units may have been affected. The first step is a screen for potential impairment, while the second step measures the amount of the impairment, if any. The Company completed the transitional goodwill impairment test during the second quarter of 2002 and found no instances of impairment.

Other than the $24 million adjustment made during the first quarter of 2002 to the carrying amount of goodwill recognized as part of the purchase of Louis Dreyfus Natural Gas Corp. (Louis Dreyfus), there were no significant changes in the carrying amount of goodwill during the first nine months of 2002 (see Note 5). In addition, all of the goodwill arising from the Louis Dreyfus acquisition has been allocated to the Exploration and Production segment for purposes of impairment testing under SFAS No. 142.

All of the Company's intangible assets, other than goodwill, are subject to amortization. Amortization expense for intangible assets was $5 million and $14 million for the three and nine months ended September 30, 2002, respectively, and $5 million and $13 million for the three and nine months ended September 30, 2001, respectively. There were no material acquisitions of intangible assets during the first nine months of 2002. The components of intangible assets at September 30, 2002 were as follows:

Annual amortization expense for intangible assets is estimated to be $19 million for 2002, $18 million for 2003, $17 million for 2004, $16 million for 2005 and $15 million for 2006.

Note 5.     Acquisitions

On November 1, 2001, Dominion acquired all of the outstanding shares of common stock of Louis Dreyfus, a natural gas and oil exploration and production company headquartered in Oklahoma City, Oklahoma, for $1.8 billion in Dominion common stock and cash. Dominion acquired Louis Dreyfus by merging it into a newly formed, wholly owned subsidiary, Dominion Oklahoma Texas Exploration & Production, Inc. (DOTEPI). Immediately after the merger, Dominion contributed DOTEPI to the Company. The purchase price allocation was completed during the first quarter of 2002 upon receipt of information from outside specialists, increasing liabilities and goodwill each by $24 million.

On September 5, 2002, the Company acquired 100 percent ownership of Cove Point LNG Limited Partnership (Cove Point) from The Williams Companies (Williams) for approximately $217 million in cash. In addition, in November 2002, the Company paid Williams an additional $8 million, representing additional development costs and changes in working capital incurred by Williams prior to closing. Cove Point's assets include a liquefied natural gas import facility located near Baltimore, Maryland that is under reconstruction, a liquefied natural gas storage facility and an approximately 85-mile natural gas pipeline. The Company expects Cove Point to become fully operational in 2003 and expects to incur approximately $117 million of additional development costs. Cove Point is included in the Company's Energy operating segment.

PAGE 10

In the fourth quarter of 2001, after fully integrating the Company into Dominion's existing organization and operations, management initiated a focused review of Dominion's combined operations. As a result, the Company recognized restructuring costs, which included employee severance and related benefits and the abandonment of leased office space no longer needed.

Under the 2001 restructuring plan, the Company identified approximately 141 salaried positions to be eliminated and recorded $13 million in employee severance-related costs. Through September 30, 2002, the Company had eliminated 99 positions.

The change in the liabilities for severance and related costs and lease abandonment costs during the first nine months of 2002 is presented below:

For additional information on restructuring 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, 2001.

For the three months ended September 30, 2002 and 2001, the Company recognized total comprehensive income of $140 million and $149 million, respectively. For the nine months ended September 30, 2002 and 2001, the Company recognized total comprehensive income of $140 million and $455 million, respectively. Other comprehensive income for the three-month and nine-month periods ended September 30, 2002 and 2001 related primarily to the effective portion of the changes in fair value of derivatives designated as hedging instruments in cash flow hedges (see Note 8 for a detailed discussion).

Note 8.     Derivatives and Hedge Accounting

The Company adopted SFAS 133, Accounting for Derivative Instruments and Hedging Activities, effective January 1, 2001. In connection with this adoption, the Company recorded an 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 addition, the Company also recorded an after-tax loss of $14 million, net of income taxes of $8 million, representing the cumulative effect of adopting SFAS No. 133 in its consolidated statements of income.

As of September 30, 2002, the Company hedged its exposure to the variability in future cash flows for certain forecasted transactions over periods of one to six years. Under the provisions of SFAS 133, the Company records the effective portion of the changes in fair value of derivative contracts designated as cash flow hedges in AOCI in the consolidated balance sheets. Derivative gains and losses reported in AOCI are reclassified as earnings, in the periods in which earnings are impacted by the variability of cash flows of the underlying hedged transaction.

PAGE 11

The portion of the Company's other comprehensive income (loss) associated with the effective portion of the change in fair value of cash flow hedging derivatives, net of taxes and amounts reclassified to earnings, is as follows:

Based on balances at September 30, 2002, the Company expects to reclassify approximately $72 million of net losses from AOCI earnings during 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 prices. The effect of amounts 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.

The ineffective portion of the change in fair value of both cash flow and fair value hedging derivatives is recognized in current period earnings. In addition, for options designated either as fair value or cash flow hedges, changes in time value are excluded from the measurement of hedge effectiveness and therefore recorded in earnings. The Company recognized pre-tax increases (decreases) in earnings, representing hedge ineffectiveness and the change in time value, as follows:

Note 9.     Margin Deposit Assets and Liabilities

Amounts reported as margin deposit assets represent funds held on deposit by various counterparties that resulted from credit exposures for the Company exceeding agreed-upon credit limits. Amounts reported as margin deposit liabilities represent funds held by the Company that resulted from credit exposures for various counterparties exceeding agreed-upon credit limits. These credit limits and the mechanism for calculating the amounts to be held on deposit are determined in the International Swap Dealers Association master agreements in place between the Company and the counterparties. As of September 30, 2002 and December 31, 2001, the Company had margin deposit assets of $44 million and $20 million, respectively. There were no margin deposit liabilities at September 30, 2002. Margin deposit liabilities at December 31, 2001 were $88 million.

PAGE 12

As more fully described in Note 2 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001, the Company follows the full cost method of accounting for gas and oil exploration and production activities, as prescribed by the SEC. Under this 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 production of proved gas and oil reserves. As currently permitted by the SEC, the Company uses hedge-adjusted period-end prices to calculate the present value of estimated future net revenues. Such prices are used for the portion of anticipated production from proved reserves that is hedged by qualifying cash flow hedges. As of September 30, 2002, the use of period-end market prices rather than hedge-adjusted prices, as otherwise required by the full cost method, would not have resulted in an impairment charge. Due to the volatility of gas and oil prices, it is reasonably possible that for some quarters, the Company may satisfy the ceiling test using hedge-adjusted prices, whereas the use of period-end market prices without the effects of hedging could have resulted in an impairment charge.

Note 11.    Significant Debt Transactions

In May 2002, the Company, Dominion and Virginia Electric and Power Company (Virginia Power), a wholly owned subsidiary of Dominion, entered into two joint credit facilities that allow aggregate borrowings of up to $2 billion. The facilities include a $1.25 billion 364-day revolving credit facility that terminates in May 2003 and a $750 million three-year revolving credit facility that terminates in May 2005. These credit facilities replaced the $1.75 billion 364-day joint credit facility and Dominion's $300 million multi-year credit facility that matured during the second quarter of 2002. The new joint credit facilities will be used for working capital, as support for the combined commercial paper programs of Dominion, Virginia Power and the Company and for other general corporate purposes. The three-year facility can also be used to support up to $200 million of letters of credit. At September 30, 2002, total outstanding commercial paper supported by these facilities was $1.7 billion, of which $723 million was issued for the Company. At September 30, 2002, total outstanding letters of credit supported by the three-year facility were $65 million, which were issued for Dominion on behalf of its other subsidiaries.

Credit Facility

In August 2002, the Company entered into a $500 million credit facility. The 364-day revolving credit facility, which terminates in August 2003, will be used to support the issuance of letters of credit and commercial paper as the Company's hedging collateral requirements. At September 30, 2002, $325 million of letters of credit had been issued under this facility.

Long-Term Debt

In January 2002, the Company redeemed $6 million of its 9.25 percent senior notes due June 15, 2004 at a repurchase price of 101 percent of principal plus accrued interest. The redemption was required as a result of the exercise of options by holders of the notes under terms of the applicable indenture. The loss on extinguishment was immaterial.

At September 30, 2002, the Company had $1.5 billion of available capacity under a shelf registration with the SEC that would permit the Company to issue debt and trust preferred securities to meet future capital requirements.

Note 12.    Dividend Restrictions

The 1935 Act prohibits registered holding companies and their subsidiaries from paying dividends out of capital or unearned surplus except when they have received specific SEC authorization. In January 2002, the Company filed an application with the SEC for relief from the restriction on paying dividends out of the unearned surplus of DOTEPI, the subsidiary into which Louis Dreyfus was merged. The request was for relief of up to an amount equal to Louis Dreyfus' retained earnings before the merger. As of September 30, 2002, the application was still pending with the SEC.

PAGE 13

Other than the fuel purchase commitments and lease commitment discussed below, there have been no significant developments with regard to commitments and contingencies, including environmental matters, as disclosed in Note 21 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001, nor have any significant new matters arisen during the nine months ended September 30, 2002.

The Company enters into long-term purchase commitments for natural gas primarily to supply its gas marketing and regulated distribution operations. At September 30, 2002, estimated payments under these commitments for the next five years and beyond are as follows: 2002-$64 million; 2003-$110 million; 2004-$31 million; 2005-$28 million; 2006-$26 million; and thereafter-$288 million.

Lease Commitment

A subsidiary of the Company has attained Exempt Wholesale Generator status from the Federal Energy Regulatory Commission and has entered into an operating lease agreement with another Dominion subsidiary, Dominion Equipment, Inc., to lease a power generation facility in Armstrong, Pennsylvania. The future minimum lease payments under this agreement as of September 30, 2002 are as follows: 2002-$1 million; 2003-$7 million; 2004-$13 million; 2005-$13 million; and 2006-$13 million. The facility became available for commercial operations during the second quarter of 2002. The facility's operations, included in the Company's Energy segment, had no material impact on the Company's revenue, net income or cash flows for the three and nine months ended September 30, 2002.

Equity Contribution Commitment

CNG International Corporation (CNG International), a wholly owned subsidiary, is contractually obligated to make equity contributions of up to $100 million to an equity method investee engaged in energy-related activities in Australia in the event that the equity method investee is unable to service certain debt. The Company is contractually obligated to cause CNG International to make such equity contributions. In 2000, in connection with the Company's decision to end its involvement with international activities, the Company established a liability for $100 million, reflecting amounts expected to be made pursuant to the equity contribution agreement. For more information, see Note 8 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

Guarantees and Letters of Credit

In the ordinary course of business, the Company is a party to various financial guarantees, performance guarantees and other guarantees for certain subsidiaries. The amounts subject to certain of these guarantees vary depending on the covered contracts actually outstanding at any particular point in time. Guarantees and standby letters of credit are used, when necessary, to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis. Accordingly, the Company provides guarantees to third parties, on behalf of subsidiaries, so the third parties would be willing to enter into contracts and extend sufficient credit to the subsidiaries to facilitate the accomplishment of intended commercial purposes. In such instances, guarantees may be used to limit exposures resulting from subsidiary business activities to pre-defined amounts. To the extent a liability, subject to a guarantee, has been incurred by a consolidated subsidiary, such liability is included in the Company's cons olidated financial statements. Only in those limited instances where the Company issues a guarantee on behalf of a related party that is not consolidated in the preparation of the Company's consolidated financial statements would performance under the guarantee result in the recognition of additional liabilities in the Company's consolidated financial statements.

PAGE 14

At September 30, 2002 and December 31, 2001, outstanding guarantees totaled $1.1 billion. The Company believes it unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries' obligations. As of September 30, 2002, the outstanding guarantees of $1.1 billion represented the following types of guarantees:

Guarantee of Consolidated Subsidiary Debt-The Company has guaranteed the payment of interest and principal on DOTEPI's debt of $288 million. The debt is included in the Company's consolidated balance sheet at September 30, 2002. In the event of default by DOTEPI, the Company would be obligated to repay such amounts.

Guarantees Supporting Commodity Transactions of Consolidated Subsidiaries-The Company has also guaranteed contract payments up to approximately $760 million, primarily for certain of its subsidiaries involved in natural gas and oil production and energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. To the extent that liabilities exist under the commodity-related contracts subject to these guarantees, such liabilities are included in the Company's consolidated balance sheet at September 30, 2002. If any one of these subsidiaries fails to perform or pay under the contracts and the counterparties seek performance or payment, the Company would be obligated to satisfy such obligation. The Company receives similar guarantees from counterparties as collateral for credit extended by the Company.

Other-The Company has also guaranteed amounts up to $35 million if certain environmental events should occur in the future related to gas and oil producing activities conducted by some of the Company's subsidiaries. If a liability should result from a future environmental event associated with such subsidiaries' operations, the liability would be reported in the Company's consolidated balance sheet.

Standby Letters of Credit

At September 30, 2002, the Company had authorized the issuance of standby letters of credit by financial institutions totaling $325 million, for the benefit of counterparties that had extended credit to the Company. In the unlikely event that the Company does not pay amounts when due under the covered contracts, the counterparties may present their claims for payment to the financial institutions, which would then request payments from the Company. The letters of credit are provided under the 364-day revolving credit facility that matures in August 2003 (see Note 11). As of September 30, 2002, no amounts had been presented for payment under these letters of credit.

The Company exchanges certain quantities of natural gas with Dominion affiliates at index prices in the ordinary course of business. The affiliated commodity transactions are presented below:

PAGE 15

The Company enters into certain commodity derivative contracts with Dominion affiliates. These contracts, which are principally comprised of commodity swaps, are used by the Company to manage commodity price risks associated with the purchases and sales of natural gas. The Company designates the majority of these contracts as cash flow hedges for accounting purposes. At September 30, 2002 and December 31, 2001, the Company's consolidated balance sheets included derivative assets with Dominion affiliates of $35 million and $56 million and derivative liabilities with Dominion affiliates of $39 million and $158 million, respectively. Unrealized gains or losses, representing the effective portion of the changes in fair value of these affiliate derivative contracts, are included in the balance of accumulated other comprehensive income in the Company's consolidated balance sheets. See Note 8 for further discussion of the Company's hedging activities.

The Company's income from operations includes the recognition of the following derivative gains and losses on affiliated transactions:

Dominion Resources Services, Inc. (Dominion Services) provides certain administrative and technical services to the Company. The cost of services provided by Dominion Services to the Company in the third quarter of 2002 and 2001 was approximately $42 million and $38 million, respectively, and in the first nine months of 2002 and 2001 was approximately $123 million and $114 million, respectively.

During the nine months ended September 30, 2002, Dominion advanced $725 million, net of repayments, to the Company pursuant to a zero percent interest, short-term demand note (Demand Note); Dominion subsequently declared $650 million of the amounts borrowed by the Company to be an equity contribution. At September 30, 2002, the net outstanding borrowings under the Demand Note totaled $75 million.

For information about the leasing of a power generation facility in Armstrong, Pennsylvania by a subsidiary of the Company from another Dominion subsidiary, Dominion Equipment, Inc., see Note 13.

For additional information on related party transactions, see Note 23 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

Note 15.    Concentration of Credit Risk

Credit risk is the risk of financial loss to the Company if counterparties fail to perform their contractual obligations. The Company sells natural gas and provides distribution services to residential, commercial and industrial customers and transmission services to utilities and other energy companies. These transactions principally occur in the Northeast, Midwest and Mid-Atlantic regions of the United States. Management does not believe that this geographic concentration contributes significantly to the Company's overall exposure to credit risk. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers.

Dominion and its subsidiaries, including the Company, maintain credit policies with respect to their counterparties that management believes minimize overall credit risk. Where appropriate, such policies include the evaluation of a prospective counterparty's financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. Dominion, on behalf of the Company and its subsidiaries, also monitors the financial condition of existing counterparties on an ongoing basis. The Company maintains a provision for credit losses based upon factors surrounding the credit risk of its customers, historical trends and other information. Management believes, based on Dominion's credit policies and the Company's September 30, 2002 provision for credit losses, that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty no nperformance.

PAGE 16

The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist) prior to the application of collateral. In the calculation of net credit exposure, the Company's gross exposure is reduced by collateral made available by counterparties, including letters of credit and cash received by the Company and held as margin deposits. Presented below is a summary of the Company's gross and net credit exposure as of September 30, 2002. The amounts presented exclude accounts receivable for gas sales and services and regulated gas transmission services and the Company's provision for credit losses.

Note 16.    Operating Segments

The Company manages its operations through the following operating segments:

The Delivery segment manages the Company's retail gas distribution systems and customer service operations.

The Energy segment manages the Company's pipeline, storage and by-product operations, certain gas production operations and the activities of the Company's gas marketing subsidiaries.

The Exploration and Production segment manages the Company's gas and oil exploration, development and production operations.

The Company also reports its corporate and other operations as an operating segment. The Corporate and Other segment includes:

• Activities of CNG International and other minor subsidiaries;
• Costs of the Company's corporate operations;
• Certain expenses which are not allocated to the other operating segments; and
• Costs associated with the cumulative effect of adopting SFAS No. 133 of $22 million ($14 million after taxes) in 2001.

PAGE 17

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 24 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

PAGE 18

Management's Discussion and Analysis of Results of Operations (MD&A) discusses the results of operations and general financial condition of Consolidated Natural Gas Company. MD&A should be read in conjunction with the Consolidated Financial Statements. "The Company" is used throughout MD&A and, depending on the context of its use, may represent any of the following: the legal entity, Consolidated Natural Gas Company, one of the Consolidated Natural Gas Company's consolidated subsidiaries or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries. The Company is a wholly owned subsidiary of Dominion.

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

The Company makes forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ are often presented with the forward-looking statements themselves. In addition, other factors could cause actual results to differ materially from those indicated in any forward-looking statement. These factors include weather conditions; fluctuations in energy-related commodities prices and the effect these could have on the Company's earnings, liquidity position, and the underlying value of its assets; counterparty credit risk; capital market conditions, including equity price risk due to marketable equity securities held as investments in trusts and benefit plans; changes in rating agency requirements; changes in accounting standards; the risks of operating businesses in regulated industries that are in the process of becoming deregulated; completing the divestiture of CNG International; collective bargaining agreements and labor negotiations; and political and economic conditions (including inflation rates). Some more specific risks are discussed below.

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

The Company's Operations Are Weather Sensitive-The Company's results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for natural gas and affect the price of energy commodities. In addition, severe weather, including hurricanes, can be destructive, disrupting operations and causing unusual maintenance or repairs.

The Company Is Subject to Complex Government Regulation Which Could Adversely Affect Its Operations-The Company's operations are subject to extensive regulation and require numerous permits, approvals and certificates from various federal, state and local governmental agencies. The Company must also comply with environmental legislation and other regulations. Management believes the necessary approvals have been obtained for the Company's existing operations and that its business is conducted in accordance with applicable laws. However, the Company remains subject to a varied and complex body of laws and regulations. New laws or regulations or the revision or reinterpretation of existing laws or regulations may require the Company to incur additional expenses.

PAGE 19

Costs of Environmental Compliance, Liabilities and Litigation Could Exceed the Company's Estimates-The Company is subject to rising costs that result from a steady increase in the number of federal, state and local laws and regulations designed to protect the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. In addition, the Company may be a responsible party for environmental clean up at a site identified by a regulatory body. Management cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs and compliance, and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially resp onsible parties.

The Use of Derivative Contracts Could Result in Financial Losses-The Company uses derivatives including futures, forwards, options and swaps, to manage its commodity and financial market risks. In the future, the Company could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these instruments involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts. For additional information concerning derivatives, see Management's Discussion and Analysis of Results of Operations-Market Rate Sensitive Instruments and Risk Management and Notes 2 and 11 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

The Company's Exploration and Production Business is Dependent on Factors Including Commodity Prices Which Cannot Be Predicted or Controlled-The Company's exploration and production business is subject to numerous risks beyond its control. These factors include fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities and the Company's ability to acquire additional land positions in competitive lease areas. Also, in connection with the use of financial derivatives to hedge future sales of gas and oil production, the Company's liquidity may sometimes be affected by margin requirements, whereby the Company must deposit funds with counterparties to cover the fair value of covered contracts in excess of agreed-upon credit limits. Some of those factors could have compounding effects that could further affect the Company's financial results. For example, because the Company follows the full cost method of accounting for gas and oil exploration and production activities, short-term market declines in the prices of natural gas and oil could adversely affect its financial results. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. The principal limitation is that these capitalized amounts may not exceed the present value of estimated future net revenues based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test). If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

An Inability to Access Financial Markets Could Affect the Execution of the Company's Business Plan-The Company relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow of its operations. Management believes that the Company will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of the Company's control may increase its cost of borrowing or restrict its ability to access one or more financial markets. Such disruptions could include an economic downturn, the bankruptcy of an unrelated energy company or changes to the Company's credit ratings. Restrictions on the Company's ability to access financial markets may affect its ability to execute its business plan as scheduled.

Changing Rating Agency Requirements Could Negatively Affect the Company's Growth and Business Strategy-As of October 2002, the Company's senior unsecured debt is rated BBB+, stable outlook, by Standard & Poor's, and A3, negative outlook, by Moody's. Both agencies have recently implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, the Company may find it necessary to take steps or change its business plans in ways that may adversely affect its growth and earnings. A reduction in the Company's credit ratings by either Standard & Poor's or Moody's could increase its borrowing costs and adversely impact its results of operations.

PAGE 20

Potential Changes in Accounting Practices May Adversely Affect the Company's Financial Results-Recently discovered accounting irregularities in various industries have caused regulators and legislators to take a renewed look at accounting practices, financial disclosures and companies' relationships with their independent auditors. While it is still unclear what laws or regulations will develop, the Company cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or in its operations specifically.

In addition, new accounting standards could be enacted by the FASB or the SEC which could impact the way the Company is required to record revenues, expenses, assets and liabilities. These changes in accounting standards could lead to negative impacts on reported earnings or increases in liabilities, which in turn could affect the Company's reported results of operations.

In general, management's discussion of the Company's results of operations focuses on the contributions of its operating segments. The Company is organized primarily on the basis of products and services sold in the United States. The Company manages its operations based on the three primary operating segments: Delivery, Energy and Exploration and Production. For additional information on the Company's operating segments, see Note 16 to the Consolidated Financial Statements.

See MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2001 for a detailed discussion of the Company's critical accounting policies. These policies include the accounting for risk management contracts at fair value, accounting for gas and oil operations and accounting for regulated operations.

Results of Operations

The Company's discussion of its results of operations includes a summary of contributions by the operating segments to net income, an overview of consolidated results of operations and a more detailed discussion of the results of operations of the operating segments.

PAGE 21

CONSOLIDATED NATURAL GAS COMPANY

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

Net income for the third quarter of 2002 was $113 million, an increase of $37 million, as compared with net income of $76 million in the same quarter of 2001. The quarterly results of 2002 reflected higher gas and oil production revenue, attributable primarily to the addition of DOTEPI, and lower regulated sales and service revenue, as compared to the same period in 2001. In addition, the Company's effective tax rate decreased, reflecting a $15 million net effect, allocated to the Company, of including certain subsidiaries in Dominion's consolidated state income tax returns.

Overview of Consolidated Operating Results-Nine Months Ended September 30, 2002

Net income was $418 million for the nine months ended September 30, 2002, as compared to $314 million in the comparable period of 2001, representing an increase of $104 million. The nine-month results of 2002 reflected higher gas and oil production revenue, attributable primarily to the addition of DOTEPI, offset by the effects of lower regulated sales and service revenue and lower nonregulated gas sales revenue, as compared to the same period in 2001. In addition, the Company's effective tax rate decreased, reflecting a $15 million net effect, allocated to the Company, of including certain subsidiaries in Dominion's consolidated state income tax returns.

As a general rule, operating results can be affected by regulatory delays when price increases are sought through general rate filings to recover certain higher costs of operations due to the regulated nature of the Delivery segment and the transmission business of the Energy segment. Weather is also an important factor since a major portion of the gas sold or transported by the distribution and transmission operations is ultimately used for space heating.

Operating Results-Third Quarter Ended September 30, 2002

The Company's Delivery segment had a net loss of $3 million in the third quarter of 2002, as compared to a net loss of $9 million in the same quarter of 2001. The quarterly results for the Delivery segment reflected lower regulated gas sales revenue, offset by the effects of lower purchased gas costs and lower operations and maintenance expense, as compared to the same period in 2001.

PAGE 22

For the combined regulated gas sales and gas transport service activities, revenues decreased by $36 million for the third quarter ended September 30, 2002, as compared to the same quarter in 2001. The decrease in revenue was substantially offset by lower purchased gas costs of $30 million for the respective quarter. As compared to the third quarter of 2001, the lower regulated gas sales revenue and purchased gas costs in the third quarter of 2002 reflected lower natural gas prices and lower volumes due to comparably warmer weather during the quarter. There were 113 fewer heating degree-days (74 percent lower) in the franchise service areas in the three-month period of 2002, as compared to the same period in 2001. There was no significant change in the status of regulated sales customers and transport customers under the customer choice programs in the third quarter of 2002 when compared to the same quarter in 2001. Operations and maintenance expense was lower in the three-month period ended September 30, 2002, as compared to the same period in 2001, primarily due to reductions in salary expense and overall operating costs.

Total throughput for the Delivery segment was lower in the third quarter of 2002, as compared to the same period in 2001. The quarterly results reflected lower volumes in both sales and transport for residential and commercial customers, as compared to the third quarter ended September 30, 2001. The lower sales and transport volumes reflected fewer heating degree-days in the third quarter of 2002, as compared to the same period in 2001. Total deliveries to industrial customers were 24 billion cubic feet (bcf) in the third quarter of 2002, as compared to 22 bcf in the same period of 2001.

Operating Results-Nine Months Ended September 30, 2002

The Delivery segment contributed $91 million to net income for the nine months ended September 30, 2002, as compared to $89 million for the same period in 2001. The nine-month results for the Delivery segment reflected lower regulated gas sales revenue, offset by the effects of higher transportation revenue, lower purchased gas costs and lower operations and maintenance expense, as compared to the same period in 2001.

For the combined regulated gas sales and gas transport service activities, revenues decreased by $562 million for the nine months ended September 30, 2002, as compared to the same period in 2001. The decrease in revenue was substantially offset by a decrease of $513 million in purchased gas costs for the nine-month period in 2002. For the nine months ended September 30, 2002, the lower regulated gas sales revenue and purchased gas costs reflected both lower natural gas prices and lower volumes, as compared to the nine-month period in 2001. The lower regulated gas sales volumes reflected customers opting for alternate suppliers under customer choice programs and the comparably milder weather experienced in Delivery's service territories in the nine months ended September 30, 2002. There were 329 fewer heating degree-days (9 percent lower) in the franchise service areas in the nine-month period of 2002, as compared to the same period in 2001. The migration of regulated customers from sales t o transport service in the nine-month period ended September 30, 2002 increased approximately 27 percent under the customer choice programs, as compared to the same period in 2001. Operations and maintenance expense was lower for the nine months ended September 30, 2002, as compared to the same period in 2001. The decrease in operations and maintenance expense was due primarily to reductions in salary expense and overall operating costs in 2002 and an additional provision for uncollectible customer accounts expense in 2001 as a result of an increase in delinquent customer accounts due to extremely high natural gas costs.

Total throughput for the Delivery segment was lower for the nine months ended September 30, 2002, as compared to the same period in 2001. The nine-month results reflected lower sales volumes, but higher volumes transported, for residential and commercial customers, when compared to the comparable nine-month period in 2001. The lower sales volumes for the nine-month period of 2002, as compared to the nine-month period in 2001, reflected fewer heating degree-days in 2002. Higher transport volumes in the nine-month period of 2002 were due primarily to the migration of residential and commercial customers from sales to transport service under customer choice programs. Total deliveries to industrial customers were 79 bcf in the nine months ended September 30, 2002; unchanged from the comparable period of 2001.

PAGE 23

Nonregulated gas sales volumes were lower in the third quarter of 2002, resulting in a $13 million decrease in revenue. The lower sales volumes in 2002 reflected warmer weather, as compared to the same period in 2001. The average realized price per thousand cubic feet (mcf) was $3.55, as compared to $3.56 in the comparable quarter of 2001. The decrease in nonregulated gas sales revenue was offset by a decrease of $29 million in purchased gas costs for the quarter ended September 30, 2002, as compared to 2001. Gas transportation revenue in the third quarter of 2002 decreased $27 million, as compared to the third quarter of 2001, reflecting lower average rates.

Operating Results-Nine Months Ended September 30, 2002

The Company's Energy segment contributed $147 million for the nine months ended September 30, 2002, as compared to $123 million in the same period of 2001. The nine-month results for the Energy segment reflected lower nonregulated gas sales and gas transportation revenue, offset by the effects of lower operating costs, principally in purchased gas costs, as compared to the same period in 2001.

Nonregulated gas sales volumes were lower in the nine-month period ended September 30, 2002, reflecting milder weather as compared to the comparable period in 2001. The average sales price realized was $3.67 per mcf in the nine-month period ended September 30, 2002, as compared to $5.15, reflecting a $1.48 decrease from the comparable period in 2001. Nonregulated gas sales revenue decreased by $263 million for the nine-month period of 2002, as compared to the same period in 2001, reflecting the effect of significantly higher sales prices in the comparable period of 2001. The decrease in nonregulated gas sales revenue was offset by a decrease of $284 million in purchased gas costs for the nine months ended September 30, 2002, as compared to the same period in 2001. Gas transportation revenue decreased $37 million in the nine-month period of 2002, as compared to the same period in 2001, reflecting lower rates, partially offset by higher transportation volumes.

PAGE 24

           bbl = barrel
           bcf = billion cubic feet
           mcf = thousand cubic feet

The gas and oil production revenue increased $50 million to $265 million in the third quarter of 2002, reflecting higher overall gas and oil production levels, offset partially by the effects of lower average realized prices, as hedged, as compared to the same quarter of 2001. The higher production levels were attributable primarily to the addition of DOTEPI, when compared to the same quarter in 2001. For a discussion of the Company's acquisition of DOTEPI, see Note 5 to the Consolidated Financial Statements. The average realized hedged gas prices were $3.55 per mcf in the three months ended September 30, 2002, as compared to $5.00 per mcf, reflecting a $1.45 decrease from the comparable period in 2001. The average realized hedged oil prices were $24.85 per bbl in the three-month period ended September 30, 2002, as compared to $25.54 per bbl from the comparable period in 2001.

The increased gas and oil production revenue for the quarter ended September 30, 2002 was partially offset by higher operating costs, reflecting the additional production costs of DOTEPI. The higher operating costs included $44 million of depreciation, depletion and amortization expense for the quarter ended September 30, 2002. Interest expense was also higher in the third quarter of 2002, due primarily to the addition of DOTEPI, as compared to the same period ended September 30, 2001.

PAGE 25

The Company's Exploration and Production segment contributed $174 million to net income for the nine months ended September 30, 2002, as compared to $131 million in the same period of 2001. The nine-month results for the Exploration and Production segment reflected higher gas and oil production revenue, partially offset by higher depreciation, depletion and amortization, operations and maintenance and interest expenses, as compared to the same period in 2001.

The gas and oil production revenue increased $237 million to $761 million in the nine months ended September 30, 2002, as compared to the same period in 2001, reflecting higher overall gas and oil production levels, offset partially by the effects of lower average realized hedged prices. The higher production levels were attributable primarily to the addition of DOTEPI, when compared to the same period in 2001. The average realized hedged gas prices were $3.52 per mcf in the nine months ended September 30, 2002, as compared to $3.91 per mcf over the same period in 2001. The average realized hedged oil prices were $23.37 per bbl in the nine months ended September 30, 2002, as compared to $26.45 per bbl from the comparable period in 2001.

The increased gas and oil production revenue for the nine-month period of 2002 was partially offset by higher operating costs, including increases of $122 million in depreciation, depletion and amortization expense and $36 million in operations and maintenance expense, as compared to the same period in 2001. Interest expense was also higher in the nine-month period of 2002, due primarily to the addition of DOTEPI, as compared to the same nine-month period ended September 30, 2001.

Overview of Operating Results-Three Months Ended September 30, 2002

Net income for the Corporate and Other segment was $11 million for the quarter ended September 30, 2002, as compared to net income of $1 million for the comparable period in 2001. The increase in net income in the quarter ended September 30, 2002, as compared to the same quarter in 2001, reflected a $12 million net effect, allocated to the Company, of including certain subsidiaries in Dominion's consolidated state income tax returns and $2 million of higher equity investment earnings, offset by $4 million of higher interest expense.

Overview of Operating Results-Nine Months Ended September 30, 2002

Net income for the Corporate and Other segment was $6 million for the nine months ended September 30, 2002, as compared to a net loss of $29 million for the comparable period in 2001. The increase in net income in the nine months ended September 30, 2002, as compared to the same nine-month period in 2001, reflected a $12 million net effect, allocated to the Company, of including certain subsidiaries in Dominion's consolidated state income tax returns, $9 million of higher equity investment earnings and other income, and a $14 million loss in 2001, representing the cumulative effect from the adoption of SFAS No. 133.

PAGE 26

For a discussion of matters that may affect the Company and its future operations, see Future Issues and Outlook in Management's Discussion and Analysis of Results of Operations in the Company's Annual Report on Form 10-K for the year ended December 31, 2001.

The Internal Revenue Code Section 29 "Credit for the Production of Fuel from Nonconventional Sources" (also referred to as the production tax credit) allows income tax credits for certain qualified production, including some natural gas, sold before December 31, 2002. Congress has not acted on legislation to extend this credit beyond 2002 for most qualified production. Whether Congress will take any action to extend the credit is uncertain. The Company expects to utilize approximately $10 million of these credits for the year ending December 31, 2002.

During the fourth quarter, Dominion routinely measures the benefit obligations and funded status of its pension and other postretirement benefit plans, in which the Company's employees participate, and prepares estimates of net periodic benefit costs for the following year after assuming then current market conditions. For its pension plans, Dominion expects that reductions in assumed discount rates and long-term rates of return on plan assets may be required, resulting in a decrease to net periodic pension income for 2003 and a decline in the net overfunded status as of December 31, 2002. For other postretirement benefits, these same factors are expected to result in increases in the net periodic benefit cost and the net unfunded status of those plans. Dominion has not measured the impact of these assumption changes as of the filing of this Form 10-Q.

In 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No. 143, Accounting for Asset Retirement Obligations. See Notes 3 and 4 to the Consolidated Financial Statements for a discussion of the impact of adopting these new standards.

PAGE 27

ITEM 4. CONTROLS AND PROCEDURES

Senior management, including the Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures during the month of October and the week of November 4, 2002. Based on this evaluation process, the Chief Executive Officer and Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective. Since that evaluation process was completed, there have been no significant changes in internal controls or in other factors that could significantly affect these controls.

PAGE 28

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 the Company, 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.

In 1999, Quinque Operating Co. and others filed a class action suit against approximately 300 defendants, including the Company and certain of its subsidiaries, in Stevens County, Kansas. The complaint seeks damages for alleged fraud, misrepresentation, conversion and assorted other claims, in the measurement and payment of gas royalties from privately held gas leases. Discovery is currently underway regarding class certification and personal jurisdiction. The court has denied the defendants' motion seeking to dismiss this action on issues other than personal jurisdiction. Oral argument is scheduled for November 2002 to determine if the case should be certified as a class action. The Company has been dismissed from the case, but certain subsidiaries of the Company remain as defendants in the matter.

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 Risk Factors and Cautionary Statements That May Affect Future Results in Part I, Item 2 for discussion of various risk factors and uncertainties that may affect the future of the Company.

In October 2002, the Public Utilities Commission of Ohio (PUCO) announced that it will conduct a review of Ohio's major public utilities, including the Company's subsidiary The East Ohio Gas Company, to ensure that the financial condition and service quality of Ohio's regulated utilities are not adversely affected by unregulated activities of parent or affiliated companies. PUCO has not requested financial data from the Ohio's regulated utilities at this time, but has solicited comments from the utilities and interested parties.

When necessary, the Company's gas distribution subsidiaries seek general rate increases on a timely basis to recover increased operating costs and to ensure that rates of return are compatible with the cost of raising capital. In addition to general rate increases, certain gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. These purchased gas costs are recovered through a mechanism that ensures dollar for dollar recovery of prudently incurred costs.

In July 2002, Greenbrier Pipeline Company, LLC submitted its application for a FERC certificate to construct and operate its proposed Greenbrier Pipeline. The 280-mile Greenbrier Pipeline is planned to originate in Kanawha County, West Virginia and extend to Granville County, North Carolina. The Company owns 67 percent of Greenbrier Pipeline Company, LLC, with Piedmont Natural Gas owning the remaining 33 percent. In October 2002, FERC gave preliminary approval for the proposed project.

In October 2002, Dominion announced the retirement of Edgar M. Roach, Jr. as Director and Executive Vice President and James P. O'Hanlon as Executive Vice President of Consolidated Natural Gas Company, effective December 1, 2002. Messrs. Roach and O'Hanlon will continue as officers of Dominion Services through February 1, 2003 to assist with transitional matters.

PAGE 29

I, Thos. E. Capps, certify that:

1. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
2. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
3. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

1. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
2. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 

I, Thomas N. Chewning, certify that:

1. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
2. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
3. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

1. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
2. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and