10-Q

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

____________

FORM 10-Q
____________

(Mark one)

X    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003

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 1-2255

VIRGINIA ELECTRIC AND POWER COMPANY
(Exact name of registrant as specified in its charter)

VIRGINIA (State or other jurisdiction of incorporation or organization)	54-0418825 (I.R.S. Employer Identification No.)
701 EAST CARY STREET RICHMOND, VIRGINIA (Address of principal executive offices)	23219 (Zip Code)
(804) 819-2000 (Registrant's telephone number)

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

Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Exchange Act). Yes       No   X   

At April 30, 2003, the latest practicable date for determination, 177,932 shares of common stock, without par value, of the registrant were outstanding.

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VIRGINIA ELECTRIC AND POWER COMPANY

INDEX

		Page   Number
PART I. Financial Information
Item 1.	Consolidated Financial Statements
	Consolidated Statements of Income - Three Months Ended March 31, 2003 and 2002	3
	Consolidated Balance Sheets - March 31, 2003 and December 31, 2002	4
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4.	Controls and Procedures	30
	PART II. Other Information
Item 1.	Legal Proceedings	31
Item 4.	Submission of Matters to a Vote of Security Holders	31
Item 6.	Exhibits and Reports on Form 8-K	31

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VIRGINIA ELECTRIC AND POWER COMPANY

PART I. Financial Information
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended March 31,
	2003	2002
	(millions)
Operating Revenue	$1,511		$1,151
Operating Expenses
Electric fuel and energy purchases, net	361		290
Purchased electric capacity	161		184
Other purchased energy commodities	68		-
Other operations and maintenance	206		199
Depreciation and amortization	115		131
Other taxes	48		35
Total operating expenses	959		839
Income from operations	552		312
Other income	14		6
Interest and related charges:
Interest expense	67		73
Distributions - preferred securities of subsidiary trust	7		3
Total interest and related charges	74		76
Income before income taxes	492		242
Income taxes	186		89
Income before cumulative effect of changes in accounting principle	306		153
Cumulative effect of changes in accounting principle (net of income taxes of $51)	84		-
Net Income	390		153
Preferred dividends	3		4
Balance available for common stock	$   387		$   149

_______________

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

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	March 31, 2003	December 31, 2002*
ASSETS	(millions)
Current Assets
Cash and cash equivalents	$    317	$    132
Customer accounts receivable (net of allowance of $19 in 2003 and $12 in 2002)	2,638	1,758
Other accounts receivable	60	73
Receivables from affiliates	38	41
Inventories	317	446
Derivative and energy trading assets	1,733	1,261
Prepayments	28	47
Other	134	108
Total current assets	5,265	3,866
Investments
Nuclear decommissioning trust funds	819	838
Other	22	22
Total investments	841	860
Property, Plant and Equipment
Property, plant and equipment	18,178	17,797
Accumulated depreciation and amortization	(7,583)	(8,240)
Total property, plant and equipment, net	10,595	9,557
Deferred Charges and Other Assets
Regulatory assets	338	239
Other	646	641
Total deferred charges and other assets	984	880
Total assets	$17,685	$15,163

  _______________

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

* The Consolidated Balance Sheet at December 31, 2002 has been derived from the audited Consolidated Financial
    Statements at that date.

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	March 31, 2003	December 31, 2002*
LIABILITIES AND SHAREHOLDER'S EQUITY	(millions)
Current Liabilities
Securities due within one year	$     600	$     360
Short-term debt	43	443
Accounts payable, trade	2,597	1,591
Payables to affiliates	71	56
Affiliated current borrowings	-	100
Accrued interest, payroll and taxes	287	207
Derivative and energy trading liabilities	1,715	1,206
Other	191	206
Total current liabilities	5,504	4,169
Long-Term Debt	3,948	3,794
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	1,894	1,763
Asset retirement obligations	708	-
Derivative and energy trading liabilities	234	279
Other	166	170
Total deferred credits and other liabilities	3,002	2,212
Total liabilities	12,454	10,175
Commitments and Contingencies (See Note 11)
Company Obligated Mandatorily Redeemable    Preferred Securities of Subsidiary Trust**	400	400
Preferred stock not subject to mandatory redemption	257	257
Common Shareholder's Equity
Common stock, no par, 300,000 shares authorized, 177,932 shares outstanding	2,888	2,888
Other paid-in capital	16	16
Accumulated other comprehensive income (loss)	(10)	8
Retained earnings	1,680	1,419
Total common shareholder's equity	4,574	4,331
Total liabilities and shareholder's equity	$17,685	$15,163

_______________

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

* The Consolidated Balance Sheet at December 31, 2002 has been derived from the audited Consolidated Financial
    Statements at that date.

**Debt securities issued by Virginia Electric and Power Company constitute 100 percent of the trust's assets.

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended March 31,
	2003	2002
	(millions)
Operating Activities
Net Income	$390	$153
Adjustments to reconcile net income to net cash from operating activities:
Cumulative effect of changes in accounting principle, net of income taxes	(84)	-
Depreciation and amortization	130	153
Deferred income taxes and investment tax credits, net	87	(2)
Deferred fuel expenses, net	(94)	22
Net unrealized (gains) on energy-related derivatives held for trading purposes	(107)	(3)
Changes in:
Accounts receivable	(867)	(50)
Affiliated accounts receivables and payables	17	(22)
Inventories	129	27
Prepayments	19	94
Accounts payable, trade	1,006	27
Accrued interest, payroll and taxes	80	34
Margin deposit assets and liabilities	(21)	(24)
Other	(19)	(88)
Net cash provided by operating activities	666	321
Investing Activities
Plant expenditures and other property additions	(199)	(170)
Nuclear fuel	(28)	(6)
Other	(9)	(7)
Net cash used in investing activities	(236)	(183)
Financing Activities
Repayment of short-term debt, net	(400)	(191)
Repayment of short-term borrowings from parent	(100)	-
Issuance of long-term debt	400	533
Repayment of long-term debt	(12)	(309)
Common stock dividend payments	(125)	(135)
Other	(8)	(14)
Net cash used in financing activities	(245)	(116)
Increase in cash and cash equivalents	185	22
Cash and cash equivalents at beginning of period	132	84
Cash and cash equivalents at end of period	$    317	$ 106
Supplemental Cash Flow Information
Noncash exchange of mortgage bonds for senior notes	$  -	$  117

_______________

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

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Nature of Operations

Virginia Electric and Power Company (Virginia Power or the Company), a Virginia public service company, is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). The Company is a regulated public utility that generates, transmits and distributes electric energy within a 30,000 square-mile area in Virginia and northeastern North Carolina. It sells electricity to approximately 2.2 million retail customers, including governmental agencies, and to wholesale customers such as rural electric cooperatives, municipalities, power marketers and other utilities. The Virginia service area comprises about 65 percent of Virginia's total land area but accounts for over 80 percent of its population. The Company has trading relationships beyond the geographic limits of its retail service territory and buys and sells wholesale electricity, natural gas and other energy commodities. Within this document, the term "Company" refers to the entirety of Virginia Electric and Power Company, including its Virginia and North Carolina operations, and all of its subsidiaries.

The Company manages its daily operations through two operating segments, Energy and Delivery. In addition, the Company also presents its corporate and other operations as a segment. See Note 14.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), the accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited Consolidated Financial Statements prepared in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles). These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

In the opinion of the Company's management, the accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly the Company's financial position as of March 31, 2003 and its results of operations and cash flows for the three-month periods ended March 31, 2003 and 2002.

The accompanying unaudited Consolidated Financial Statements represent the accounts of the Company and its subsidiaries, with all significant intercompany transactions and accounts eliminated in consolidation.

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.

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, 2002 for more 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 and other factors.

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Certain amounts in the 2002 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation.

Depreciation

In 2002, the Company extended the estimated useful lives of most of its fossil fuel stations and electric transmission and distribution property based on depreciation studies that indicated longer lives were appropriate. These changes in estimated useful lives reduced depreciation expense by approximately $16 million for the first quarter of 2003.

In 2001, the Company extended the estimated useful lives of its nuclear facilities by 20 years. The impact of the change is fully reflected in depreciation expense for 2003 and 2002. The Company filed applications with the Nuclear Regulatory Commission (NRC) for 20-year life-extensions for its nuclear facilities in 2001 and received a renewed license for these units in March 2003.

Note 3. Accounting Changes

Asset Retirement Obligations

Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The Company has identified certain asset retirement obligations that are subject to the standard. These obligations are primarily associated with the decommissioning of its nuclear generation facilities.

Under SFAS No. 143, asset retirement obligations will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Under the present value approach used to estimate the fair value of asset retirement obligations, accretion of the liabilities due to the passage of time will be recognized as an operating expense. In addition, the reporting of realized and unrealized earnings of external trusts available for funding decommissioning activities at the Company's nuclear plants will be recorded in other income and other comprehensive income, as appropriate. Through 2002, the Company recorded these trusts' earnings in other income with an offsetting charge to expense, also recorded in other income, for the accretion of the decommissioning liability.

The effect of adopting SFAS No. 143 for the three months ended March 31, 2003, as compared to an estimate of net income reflecting the continuation of former accounting policies, was to increase net income by $145 million. The increase reflects lower expenses under SFAS No. 143 compared to expenses that would have been recorded under the former accounting policies. The $145 million increase is comprised of a $139 million after-tax gain, representing the cumulative effect of a change in accounting principle, described below, and an increase in income before the cumulative effect of a change in accounting principle of $6 million. Under the Company's accounting policy prior to the adoption of SFAS No. 143, $838 million had previously been accrued for future asset removal costs, primarily related to future nuclear decommissioning. Such amounts are included in the accumulated provision for depreciation and amortization as of December 31, 2002. With the adoption of SFAS No. 143, the Company calculated its ass et retirement obligations to be $697 million. In recording the cumulative effect of the accounting change, the Company recognized the reduction attributable to the remeasurement of asset retirement obligations and reclassified such amount from the accumulated provision for depreciation and amortization to other non-current liabilities. The cumulative effect of the accounting change also reflected a $175 million increase in property, plant and equipment for capitalized asset retirement costs and a $77 million increase in the accumulated provision for depreciation and amortization, representing the depreciation of such costs through December 31, 2002.

See Notes 2 and 8 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for further discussion of the Company's former accounting and reporting policies for its costs of removal, including nuclear decommissioning, and earnings on its decommissioning trusts. See also Note 10 to these financial statements for additional disclosures regarding asset retirement obligations.

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Energy Trading Contracts

In October 2002, the Emerging Issues Task Force (EITF) reached consensus on EITF Issue No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. EITF 02-03, in part, rescinded EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. As a result, certain energy-related commodity contracts that are held for trading purposes are no longer subject to fair value accounting. The affected contracts are those energy-related contracts held for trading purposes that are not considered to be derivatives under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Under EITF 98-10 accounting, the fair value of energy contracts was measured at each reporting date, with changes in fair value, including unrealized amounts, reported in earnings. Energy-related contracts affected by the rescission of EITF 98-10 are n ow subject to accrual accounting and recognized as revenue or expense at the time of contract performance, settlement or termination.

The EITF 98-10 rescission was effective for all non-derivative energy trading contracts initiated after October 25, 2002. For those non-derivative energy trading contracts initiated prior to October 25, 2002, the Company reported the cumulative effect of this change in accounting principle as of January 1, 2003, resulting in an after-tax loss of $55 million.

The rescission of EITF 98-10, along with other provisions of EITF 02-03, also affects the classification of realized and unrealized gains and losses arising from derivative energy contracts, no longer considered to be held for trading purposes, on the Consolidated Statements of Income. As permitted by EITF 98-10, for periods prior to January 1, 2003, the Company presented all changes in fair value of derivative and non-derivative energy trading contracts, including amount realized upon settlement, in revenue on a net basis. Under the provisions of EITF 02-03, for those energy-related derivative instruments determined to be held for trading purposes, all changes in fair value, including amounts realized upon settlement, continue to be presented in revenue on a net basis. A derivative contract is held for trading purposes if the intent of the transaction is to generate profits on short-term differences in price. For non-trading derivatives not designated as hedges, all unrealized changes in fair value are pres ented in other operations and maintenance expense on a net basis. For non-trading derivative contracts that involve physical delivery of commodities, gross sales contract settlements are presented in revenue, while gross purchase contract settlements are reported in expenses.

Note 4. Recently Issued Accounting Standards

Amendment of SFAS No. 133

On April 30, 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The Company is evaluating SFAS No. 149 and has not yet determined the impact of adopting its provisions.

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Other SFAS No. 133 Guidance

In connection with the January 2003 EITF meeting, FASB was requested to reconsider an interpretation of SFAS No. 133. The interpretation, which is contained in the DIG's C11 guidance, relates to contracts with pricing terms that include broad market indices. In particular, that guidance discusses whether a contract with pricing that contains broad market indices (e.g., consumer price index) could qualify as a normal purchase or sale and therefore not be subject to fair value accounting. The Company has certain power purchase and sale contracts that are subject to the guidance that is being reconsidered. The aggregate fair value of these contracts at March 31, 2003 represented an estimated pretax net unrealized loss of $112 million. On April 25, 2003, FASB issued a proposal, Statement 133 Implementation Issue No. C20, Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Scope Exception, to clarify the guidance applicable to these circu mstances. The proposal is subject to public comment until May 30, 2003. Pending evaluation of the proposal and the final guidance ultimately issued by FASB, the Company has not determined the impact of this clarification onits results of operations or financial position.

Note 5. Operating Revenue

(millions)	Three Months Ended March 31,
	2003	2002
Regulated electric sales	$1,248	$1,110
Nonregulated electric sales	31	57
Nonregulated gas sales	194	(35)
Other	38	19
Total operating revenue	$1,511	$1,151

Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services subject to cost-of-service rate regulation.

Nonregulated electric sales consist primarily of sales of electricity at market-based rates and net revenue from electric trading activities.

Nonregulated gas sales consist primarily of sales of natural gas at market-based rates, brokered gas and net revenue from gas trading activities.

Other revenue consists primarily of miscellaneous service revenue from rate-regulated electric distribution, sales of coal and brokered oil and other miscellaneous revenue.

The composition of revenue from nonregulated electric sales, nonregulated gas sales, and other revenue has changed since being described in Note 5 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. The changes were effective January 1, 2003 and related to the impact of adopting EITF 02-03 on the reporting of revenue and expenses for energy trading activities, as described in Note 3.

Note 6.     Liability for 2001 Severance Costs

The Company recognized costs and related liability associated with employee severances in 2001. The change in this liability during the three-month period ended March 31, 2003 is presented below:

(millions)	Severance Liability
Balance at December 31, 2002	$4
Amounts Paid	(1)
Balance at March 31, 2003	$3

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

For additional information, see Note 6 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

Note 7. Comprehensive Income

Total comprehensive income was $372 million and $152 million for the three months ended March 31, 2003 and March 31, 2002, respectively. Other comprehensive income for these periods related primarily to unrealized losses on investments held in decommissioning trusts and the effective portion of the changes in fair value of derivatives designated as hedging instruments in cash flow hedges (as described in Note 8). See Note 3 for a discussion of accounting for unrealized gains and losses on trust investments.

Note 8. Derivatives and Hedge Accounting

The Company recognized no hedge ineffectiveness during the three-month periods ended March 31, 2003 and 2002. The Company recognized net 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, for the three-month periods ended March 31, 2003 and 2002 as follows (in millions):

	2003	2002
Other comprehensive income (loss) - cash flow hedges	$5	$(1)

The following table presents selected information related to cash flow hedges included in accumulated other comprehensive income (AOCI) in the Consolidated Balance Sheet at March 31, 2003:

	Accumulated Other Comprehensive Income (Loss) After-Tax	Portion Expected to be Reclassified to Earnings During the Next 12 Months	Maximum Term
	(millions)
Interest Rate	$(2)	$(1)	46 months
Foreign Currency	15	4	56 months
Total	$13	$ 3

The actual amounts that will be reclassified to earnings during the next 12 months will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign exchange rates. The effect of amounts being reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated purchases) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.

Note 9. Significant Financing Transactions

Long-Term Debt

In February 2003, the Company issued $400 million aggregate principal amount of its 2003 Series A 4.75 percent senior notes due March 1, 2013. The Company used the cash proceeds for general corporate purposes, including the repayment of other debt.

In February 2003, the Company repaid $10 million of maturing medium-term notes.

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 10. Asset Retirement Obligations

The following table describes the changes to the Company's asset retirement obligations during the three months ended March 31, 2003:

	Amount
	(millions)
Asset retirement obligations at January 1, 2003	-
Asset retirement obligations recognized in transition	$697
Asset retirement obligations incurred during the period	1
Asset retirement obligations settled during the period	-
Accretion expense	10
Revisions in estimated cash flows	-
Asset retirement obligations at March 31, 2003	$708

The Company has established external trusts dedicated to funding the future decommissioning of its nuclear plants. At March 31, 2003, the aggregate fair value of these trusts, consisting primarily of debt and equity securities, totaled $819 million.

Had the provisions of SFAS No. 143 been adopted on January 1, 2000, the Company's net income would have been as follows:

	Three Months Ended March 31,		Year Ended December 31,
	2003	2002	2002	2001	2000
Income before cumulative effect of a change    in accounting principle, as reported	$306				$558
Pro forma income before cumulative effect of    a change in accounting principle	$306				$572
Net income, as reported	$390	$153	$773	$446	$579
Pro forma net income	$251	$156	$778	$464	$593

Had the provisions of SFAS No. 143 been adopted on January 1, 2000, the asset retirement obligations would have been as follows:

(millions)	2000	2001	2002
Pro forma asset retirement obligations at January 1,	$588	$620	$661
Pro forma asset retirement obligations at December 31,	$620	$661	$697

In accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, the Company will continue its practice of accruing for future costs of removal for its cost-of-service rate regulated transmission and distribution assets, even if no legal obligation to perform such activities exists. At March 31, 2003 and December 31, 2002, the Company's accumulated depreciation and amortization included $383 million and $375 million, representing the estimated future cost of such removal activities, respectively.

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 11. Commitments and Contingencies

Other than the matters discussed below, there have been no significant developments regarding commitments and contingencies 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, 2002, nor have any significant new matters arisen during the first quarter of 2003.

Environmental Matters

As previously reported in Note 21 to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2002, the Company received a Notice of Violation in 2000 from the United States Environmental Protection Agency related to some specified construction projects at the Mt. Storm Power Station in West Virginia. Thereafter, New York State filed a suit against the Company alleging similar violations, and the suit was stayed. The Company reached an agreement in principle with the federal government and the state of New York to resolve the matter, and the states of Virginia, West Virginia, Connecticut and New Jersey joined the United States and the state of New York in seeking to reach a final agreement with the Company. A settlement agreement in the form of a proposed Consent Decree was agreed to on April 21, 2003, by the U.S. Department of Justice and the U.S. Environmental Protection Agency for the United States of America, by the states of Virginia, West Virginia, Connecticut, New Jersey and New York and by the Company. In accordance with the settlement, the United States filed an action in the Eastern District of Virginia against the Company and the Consent Decree was lodged with that court to settle that action. Virginia and West Virginia also filed complaints in intervention in the Virginia federal district court. The New York State federal district court action has been transferred to the Virginia federal district court and it is anticipated that, in addition to New York, Connecticut and New Jersey will join as plaintiffs in that proceeding. After an EPA public comment period, the Virginia federal district court will be asked to enter the Consent Decree finalizing the settlement and resolving the underlying actions, but retaining jurisdiction pursuant to the terms of the Consent Decree. The settlement is consistent with the previously reported agreement in principle and includes payment of a $5 million civil penalty, an obligation to fund $14 million for environm ental projects and a commitment to improve air quality under the Consent Decree estimated to involve expenditures of $1.2 billion. The Company has already incurred certain capital expenditures for environmental improvements at its coal-fired stations in Virginia and West Virginia and has committed to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree. As of March 31, 2003, the Company had accrued $18 million for the civil penalty and the funding of the environmental projects, substantially all of which was recorded in 2000.

Surety Bonds

At March 31, 2003, the Company had issued $66 million of surety bonds, of which $57 million is associated with the financial assurance requirements imposed by the NRC with respect to the decommissioning of the Company's nuclear units. Under the terms of the surety bonds, the Company is obligated to indemnify the respective surety bond company for any amounts paid.

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 12. Related Party Transactions

The Company, through an unregulated subsidiary, exchanges certain quantities of natural gas with affiliates at market prices in the ordinary course of business. The Company purchased approximately $123 million and $28 million of natural gas, gas transportation and storage services from other Dominion affiliates and sold approximately $144 million and $39 million of natural gas to affiliates in the first quarter of 2003 and 2002, respectively.

Through the same unregulated subsidiary, the Company is involved in facilitating Dominion's enterprise risk management strategy. In connection with this strategy, the Company enters into certain commodity derivative contracts with other Dominion affiliates. These contracts, which are principally comprised of commodity swaps, are used by Dominion affiliates to manage commodity price risks associated with purchases and sales of natural gas. As part of Dominion's enterprise risk management strategy, the Company generally manages such risk exposures by entering into offsetting derivative instruments with non-affiliates. The Company reports both affiliated and non-affiliated derivative instruments at fair value, with related changes included in earnings. At March 31, 2003 and December 31, 2002, the Company's Consolidated Balance Sheets included derivative assets with Dominion affiliates of $85 million and $84 million and derivative liabilities with Dominion affiliates of $79 million and $90 million, respectively. The Company reported net realized losses of $5 million and net gains of $20 million during quarters ended March 31, 2003 and 2002, respectively, related to commodity derivative contracts with Dominion affiliates.

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 first quarters of 2003 and 2002 was approximately $72 million and $64 million, respectively. The Company provides certain services to affiliates, including charges for facilities and equipment usage. The cost of these services provided by the Company to Dominion Services and other Dominion affiliates in the first quarters of 2003 and 2002 was approximately $6 million and $5 million, respectively.

During the first quarter of 2003, unregulated subsidiaries of the Company repaid the $100 million that Dominion had advanced pursuant to a short-term demand note in 2002. Interest charges related to this note in the first quarter of 2003 were not material.

The Company's accounts receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions.

For information about the Company's agreement with Dominion Equipment II, Inc. to develop, construct, finance and lease a new power generation facility at its Possum Point station in Prince William County, Virginia, see Note 21 to the Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

An unregulated subsidiary of the Company, at its sole discretion, has provided at March 31, 2003 and December 31, 2002, approximately $24 million and $31 million of cash collateral to third parties on behalf of several of its natural gas supply customers. For this and other financial support services, the unregulated subsidiary receives fees and has a security interest in the customers' assets. The arrangements terminate at various dates beginning in 2005 through 2007, subject to periodic renewal thereafter unless terminated by either party.

For additional information on transactions with related parties, see Note 24 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

PAGE 15

VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 13.     Concentration of Credit Risk

The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative and energy trading 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 March 31, 2003. The amounts presented exclude accounts receivable for regulated electric retail distribution and regulated electric transmission services, amounts payable to affiliated companies and the Company's provision for credit losses. See Note 23 to the Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for a discussion of the nature of the Company's credit risk exposure s.

	At March 31, 2003
(millions)	Credit Exposure Before Credit Collateral	Credit Collateral	Net Credit Exposure
Investment grade(1)	$401	$ 22	$379
Non-investment grade(2)	93	31	62
No external ratings:
Internally rated-investment grade(3)	336	--	336
Internally rated-non-investment grade(4)	78	--	78
Total	$908	$53	$855

_______________________

(1) This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody's Investor Service (Moody's) and BBB- assigned by Standard & Poor's Ratings Group, a division of The McGraw-Hill Companies, Inc. (Standard & Poor's). The five largest counterparty exposures, combined, for this category represented approximately 11 percent of the total gross credit exposure.

(2) This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures, combined, for this category represented approximately 6 percent of the total gross credit exposure.

(3) This category includes counterparties that have not been rated by Moody's or Standard & Poor's but are considered investment grade based on the Company's evaluation of the counterparty's creditworthiness. The five largest counterparty exposures, combined, for this category represented approximately 25 percent of the total gross credit exposure.

(4) This category includes counterparties that have not been rated by Moody's or Standard & Poor's and are considered non-investment grade based on the Company's evaluation of the counterparty's creditworthiness. The five largest counterparty exposures, combined, for this category represented approximately 5 percent of the total gross credit exposure.

PAGE 16

VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 14. Operating Segments

The Company manages its operations through the following segments:

Energy manages the Company's portfolio of generating facilities and power purchase contracts. It also manages the Company's energy trading, marketing, hedging and arbitrage activities. Energy also manages the electric transmission business formerly managed by Delivery. Amounts for 2002 have been restated to reflect the management of electric transmission by Energy effective January 1, 2003.

Delivery manages the Company's electric distribution as well as metering services and customer service. The segment continues to be subject to the requirements of SFAS No. 71. Amounts for 2002 have been restated to reflect the management of electric transmission by Energy effective January 1, 2003.

Corporate and Other includes certain expenses which are not allocated to the Energy and Delivery segments, including those related to the following: 1) corporate operations and assets; 2) severance costs related to 2003 workforce reductions; and 3) the 2003 cumulative effect of changes in accounting principle (See Note 3).

See Note 26 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for more information about the Company's segments.

	Energy	Delivery	Corporate and Other	Consolidated Total
Three Months Ended March 31, 2003	(millions)
Operating revenue	$1,229	$280	$   2	$1,511
Net income	242	69	79	390
Three Months Ended March 31, 2002
Operating revenue	$913	$235	$3	$1,151
Net income	101	52	-	153

PAGE 17

VIRGINIA ELECTRIC AND POWER COMPANY

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

Introduction

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) discusses the results of operations and general financial condition of Virginia Power. 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, Virginia Electric and Power Company, one of Virginia Power's consolidated subsidiaries or the entirety of Virginia Power and its consolidated subsidiaries. The Company is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion).

Risk Factors and Cautionary Statements That May Affect Future Results

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; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; changes in rating agency requirements or ratings; changes in accounting standards; the risks of operating businesses in regulated industries that are becoming deregulated; transfer of control over the Company's transmis sion facilities to a regional transmission entity; 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 electricity and affect the price of energy commodities. In addition, severe weather, including hurricanes, winter storms and droughts, can be destructive, causing outages, property damage and requiring the Company to incur additional expenses.

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, new laws or regulations or the revision or reinterpretation of existing laws or regulations may require the Company to incur additional expenses.

Costs of environmental compliance, liabilities and litigation could exceed the Company's estimates. Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and 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 responsible parties.

PAGE 18

VIRGINIA ELECTRIC AND POWER COMPANY

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

Capped electric rates in Virginia may be insufficient to allow full recovery of stranded and other costs. Under the Virginia Utility Restructuring Act, the Company's base rates (excluding fuel costs and certain other allowable adjustments) remain unchanged until July 2007 unless modified or terminated consistent with that Act. The capped rates and wires charges that, where applicable, are being assessed to customers opting for alternative suppliers allow the Company to recover certain generation-related costs and fuel costs; however, the Company remains exposed to numerous risks of cost-recovery shortfalls. These include exposure to potentially stranded costs, future environmental compliance requirements, changes in tax laws, inflation and increased capital costs. See Management's Discussion and Analysis of Financial Condition and Results of Operations-Future Issues and Outlook and Note 21 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ende d December 31, 2002.

The electric generation business is subject to competition. The generation portion of the Company's operations in Virginia is open to competition and is no longer subject to cost-based rate regulation. As a result, there is increased pressure to lower costs, including the cost of purchased electricity. Because the Company's generation business has not previously operated in a competitive environment, the extent and timing of entry by additional competitors into the electric market in Virginia is unknown. Therefore, it is difficult to predict the extent to which the Company will be able to operate profitably within this new environment.

There are inherent risks in the operation of nuclear facilities. The Company operates nuclear facilities that are subject to inherent risks. These include the threat of terrorist attack and ability to dispose of spent nuclear fuel, the disposal of which is subject to complex federal and state regulatory constraints. These risks also include the cost of and the Company's ability to maintain adequate reserves for decommissioning, costs of plant maintenance and exposure to potential liabilities arising out of the operation of these facilities. The Company maintains decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks. However, it is possible that costs arising from claims could exceed the amount of any insurance coverage.

The use of derivative instruments could result in financial losses. The Company uses derivative instruments including futures, forwards, options and swaps, to manage its commodity and financial market risks. In addition, the Company purchases and sells commodity-based contracts in the natural gas, electricity and oil markets for trading purposes. 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 financial 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 the Company's derivatives and commodity-based trading contracts, se e Management's Discussion and Analysis of Financial Condition and Results of Operations-Market Rate Sensitive Instruments and Risk Management and Notes 2 and 9 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

The Company is exposed to market risks beyond its control in its energy clearinghouse operations. The Company's energy clearinghouse and risk management operations are subject to multiple market risks including market liquidity, counterparty credit strength and price volatility. Many industry participants have experienced severe business downturns during the past year resulting in some being forced to exit or curtail their participation in the energy trading markets. This has led to a reduction in the number of trading partners and lower industry trading revenues. Declining credit worthiness of some of the Company's trading counterparties may limit the level of its trading activities with these parties and increase the risk that these counterparties may not perform under a contract.

An inability to access financial markets could affect the execution of the Company's business plan. The Company relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flows of its operations. Management believes that the Company and its subsidiaries 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

PAGE 19

VIRGINIA ELECTRIC AND POWER COMPANY

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

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 May 1, 2003, the Company's senior secured debt is rated A-, stable outlook, by Standard and Poors Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor's) and A2, stable outlook, by Moody's Investor Service (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 affect operating results.

Potential changes in accounting practices may adversely affect the Company's financial results. The Company cannot predict the 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. New accounting standards could be issued by the Financial Accounting Standards Board (FASB) or the Securities and Exchange Commission (SEC) which could impact the way the Company is required to record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect the Company's reported earnings or could increase reported liabilities.

Operating Segments

In general, management's discussion of the Company's results of operations focuses on the contributions of its operating segments. However, the discussion of the Company's financial condition under Liquidity and Capital Resources is for the entire Company. The Company's two operating segments are Energy and Delivery. In addition, the Company presents its corporate and other operations, including certain expenses, which are not allocated to the Energy and Delivery segments, as a segment. For more information on the Company's operating segments, see Note 14 to the Consolidated Financial Statements.

Critical Accounting Policies

As of March 31, 2003, other than the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, there have been no significant changes with regard to critical accounting policies as disclosed in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. The policies disclosed included the accounting for risk management and energy trading contracts at fair value and accounting for regulated operations.

Asset Retirement Obligations

Effective January 1, 2003, the Company adopted SFAS No. 143, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. At March 31, 2003, the Company's asset retirement obligations totaled $708 million, the majority of which relates to the decommissioning of its nuclear units.

Asset retirement obligations are recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. In the absence of quoted market prices, the Company estimates the fair value of asset retirement obligations using present value techniques, involving discounted cash flow analysis. Measurement using such techniques is dependent upon many subjective factors, including the selection of discount and cost escalation rates, identification of planned retirement activities and related cost estimates and assertions of probability regarding the timing, nature and costs of such activities. Inputs and assumptions are based on the best information available at the time the estimates are made. However, estimates of future cash flows are highly uncertain by nature and may vary significantly from actual results.

PAGE 20

VIRGINIA ELECTRIC AND POWER COMPANY

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

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 2003 results of operations, as compared to 2002, and a more detailed discussion of the results of operations of the operating segments. The 2002 segment results have been restated to reflect the transfer of the electric transmission operations from the Delivery segment to the Energy segment.

(millions)	Net Income		Operating Revenue		Operating Expenses
Three Months Ended March 31,	2003	2002	2003	2002	2003	2002
Energy	$242	$101	$1,229	$  913	$807	$705
Delivery	69	52	280	235	141	131
Corporate and Other	79	-	2	3	11	3
Total	$390	$153	$1,511	$1,151	$959	$839

The following table provides data on electricity supplied by Energy and delivered by Delivery:

Three Months Ended March 31,	2003	2002
Energy supplied (million mwhrs)	20	18
Electricity delivered to utility customers (million mwhrs)	20	17

Consolidated Overview - First Quarter 2003

Net income increased $237 million to $390 million for the three months ended March 31, 2003 as compared to the same period in 2002. The increase includes a net $84 million after-tax gain for changes in accounting methods related to the adoption of SFAS No. 143, and the adoption of Emerging Issues Task Force Issue 02-03, Issues Involved in Accounting for Contracts under Issue No. 98-10 (EITF 02-03). Regulated electric sales increased $138 million for the first quarter of 2003, reflecting favorable weather conditions, customer growth and higher fuel rate recoveries. These recoveries are generally offset by related increases in electric fuel expense and do not materially affect income. The Company's nonregulated electric revenue decreased $26 million and nonregulated gas revenue increased $229 million, respectively for the first quarter of 2003. Other revenue increased $19 million over the same period in 2002. Factors affecting these nonregulated revenue items are discussed in the Energy Segment below.

Total operating expenses increased, compared to the first quarter of 2002, primarily due to higher electric fuel and energy purchases. As a result of implementing EITF 02-03, $68 million of other purchased energy commodities are reported as expenses in 2003. Purchased electric capacity and depreciation expense decreased, as compared to the first quarter of 2002, and is explained in the segment results below. Other taxes increased $13 million, primarily due to the impact in 2002 of a favorable resolution of sales and use tax issues and the recognition of business and occupation tax credits. Similar benefits were not recognized in the first quarter of 2003.

Adoption of EITF 02-03

Effective January 1, 2003, the Company adopted EITF Issue 02-03. It rescinds EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10). Energy manages the Company's energy trading, hedging, arbitrage and power marketing activities through the Dominion Energy Clearinghouse (Clearinghouse). The implementation of EITF 02-03 primarily affects the timing of recognition in earnings for certain Clearinghouse energy-related contracts, as well as the presentation of gains and losses associated with energy-related contracts in the Consolidated Statement of Income. The adoption of EITF 02-03 did not require restatement of prior periods. See Note 3 to the Consolidated Financial Statements.

PAGE 21

VIRGINIA ELECTRIC AND POWER COMPANY

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

The adoption of EITF 02-03 had the following initial and ongoing impact on the accounting for and presentation of Clearinghouse energy-related contracts in the Consolidated Financial Statements, effective January 1, 2003:

• Cumulative effect of adopting EITF 02-03: For all non-derivative energy contracts initiated prior to October 25, 2002, and previously designated as trading under EITF 98-10, the Company recognized a loss of $55 million (net of taxes of $35 million) as the cumulative effect of a change in accounting principle effective January 1, 2003, which is reflected in the Corporate and Other segment.
• Derivative Contracts: Energy-related derivative contracts continue to be subject to fair value accounting. Under fair value accounting, unrealized changes in fair value are recorded in earnings each reporting period, as well as amounts realized as settlements occur. For those derivatives determined to be held for trading purposes, all changes in fair value, including amounts realized upon settlement, are presented in revenue on a net basis. For non-trading derivatives not designated as hedges, all unrealized changes in fair value are presented in other operations and maintenance expense on a net basis. For non-trading derivative contracts that involve physical delivery of commodities, gross sales contract settlements are presented in revenue, while gross purchase contract settlements are reported in expenses.
• Non-Derivative Contracts: Non-derivative energy-related contracts, previously subject to fair value accounting under EITF 98-10, are now subject to accrual accounting. Under accrual accounting, the Company recognizes revenue or expense on a gross basis at the time of contract performance, settlement or termination. These contracts will no longer be reported at fair value in the Company's Consolidated Financial Statements.

As noted above, the recognition and presentation requirements of EITF 02-03 described above were applied prospectively in 2003, and the Consolidated Statement of Income for the first quarter of 2002 was not restated.

Adoption of SFAS 143

The principal impact of the Company's implementation of SFAS No. 143 is a change in the method of accounting for nuclear decommissioning. As a result of the change, the Company's income before taxes increased in 2003, as compared to 2002, by approximately $3 million. However, when comparing SFAS No. 143 to the method of accounting used for nuclear decommissioning in 2002, the components of cost are presented differently in the income statement. For the comparative periods, depreciation expense decreased $8 million. Under SFAS No. 143, the Company also recorded $10 million in 2003, representing accretion of its asset retirement obligations, in other operations and maintenance expense. Under the 2002 accounting policy, the Company recorded $5 million in other income for accretion expense related to its accumulated provision for nuclear decommissioning. For more information, see Note 3 to the Consolidated Financial Statements.

Energy Segment

First Quarter 2003 Results

Energy's net income contribution increased $141 million to $242 million for the three months ended March 31, 2003, as compared to the same period in 2002. The increase in net income primarily reflects a $316 million increase in operating revenue and an $11 million increase in other income, offset by a $102 million increase in operating expenses and an $85 million increase in income tax expense. Comparably colder temperatures and customer growth contributed approximately $75 million and $10 million, respectively, to the $92 million increase in regulated electric sales. There were 27 percent more heating degree-days in the first quarter of 2003, as compared to 2002, and there were approximately 38,000 new electric customers added over the last twelve months. Fuel rate recoveries, which are generally offset by related increases in electric fuel expense and do not materially affect net income, increased $44 million for the first quarter of 2003. Partially offsetting these increases in regulated electric sales re venue was a

PAGE 22

VIRGINIA ELECTRIC AND POWER COMPANY

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

net decrease of $18 million due to other factors. A reallocation of base rate revenue between the Delivery and Energy segments, effective January 1, 2003, decreased Energy's regulated electric sales revenue by $19 million.

Nonregulated electric sales decreased $26 million in the three months ended March 31, 2003, as compared to 2002. Clearinghouse electric revenue, net of applicable trading purchases, decreased by $33 million as compared to 2002. This decrease included the effects of unfavorable price changes on the fair value of derivative contracts held and not yet settled, lower margins and the impact of discontinuing fair value accounting for non-derivative contracts and the reclassification of purchases under derivative contracts no longer considered to be held for trading purposes after the adoption of EITF 02-03. Revenue from wholesale marketing of utility generation increased $7 million and was principally driven by higher electric prices.

Clearinghouse nonregulated gas revenue, net of applicable trading purchases, increased by $229 million, as compared to the first three months of 2002. This increase reflects the effect of favorable price changes on unsettled derivative contracts, increased volumes and impact of discontinuing fair value accounting for non-derivative contracts and the reclassification of purchases under derivative contracts no longer considered to be held for trading purposes after the adoption of EITF 02-03. Nonregulated gas revenue also reflects $18 million of realized and unrealized losses related to contracts held, by one of the Company's unregulated subsidiaries involved in Clearinghouse operations, as part of Dominion's consolidated price risk management strategy associated with anticipated sales of Dominion's 2003 natural gas production.

Other revenue increased over the same period in 2002, primarily reflecting the impact of adopting EITF 02-03. This increase included $16 million associated with oil trading revenue, net of applicable purchases, and revenue from sales of coal. Purchases of coal for this activity are reported in other purchased energy commodities expense in 2003 but were reported in other revenue in 2002.

Operating expenses increased $102 million to $807 million in the first quarter of 2003. Electric fuel and energy purchases, net increased $71 million. Energy costs increased $44 million due to higher fuel rate recoveries, $12 million for purchases not subject to fuel rate recoveries, and $6 million for expenses associated with increased wholesale marketing of utility generation. Electric fuel and energy purchases, net also increased due to the adoption of EITF 02-03, reflecting purchases under certain derivative contracts that are no longer considered held for trading purposes. Purchased electric capacity decreased $23 million, primarily due to scheduled rate reductions on certain supply contracts. Other purchased energy commodities increased $68 million reflecting the gross presentation of certain gas and coal contracts that are no longer considered held for trading purposes after the implementation of EITF 02-03.

Other operations and maintenance expense decreased $12 million primarily due to the adoption of EITF 02-03, reflecting changes in the fair value of certain derivative energy contracts that are no longer considered held for trading purposes. Increases in other operations and maintenance expense included a $27 million increase in general and administrative expenses and a $12 million increase in outage and maintenance costs at the generation stations. Also, as previously discussed, other operations and maintenance expense increased $10 million for the accretion of the nuclear decommissioning asset retirement obligation beginning in 2003.

Depreciation expense decreased $14 million, primarily reflecting a $8 million decrease related to a change in the presentation of expenses associated with asset retirement obligations pursuant to a change in accounting policy. As previously discussed, a significant component of such expenses is now reflected in other operations and maintenance beginning in 2003. The remaining decrease reflects the extension of estimated useful lives of most fossil fuel stations and electric transmission property during the second quarter of 2002, partially offset by the impact of new property additions. See Note 2 to the Consolidated Financial Statements.

Other taxes increased $12 million, primarily due to the impact in 2002 of a favorable resolution of sales and use tax issues and the recognition of business and occupation tax credits. Similar benefits were not recognized in the first quarter of 2003.

Other income also increased approximately $11 million, reflecting increased earnings of $6 million from the Company's external decommissioning trusts and $5 million as a result of accretion expense related to the Company's provision for decommissioning being reported in other income in 2002. As previously discussed,

PAGE 23

VIRGINIA ELECTRIC AND POWER COMPANY

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

accretion expense under SFAS No. 143 is reported in other operations and maintenance expense beginning in 2003.


Selected Information-Energy Trading Activities

See Selected Information-Energy Trading Activities in the MD&A of the Company's Annual Report on Form 10-K for the year ended December 31, 2002 for a detailed discussion of the energy trading, hedging and arbitrage
activities of the Clearinghouse and related accounting policies. For additional discussion of trading activities, see Market Rate Sensitive Instruments and Risk Management.

A summary of the changes in the unrealized gains and losses recognized for the Company's energy-related derivative instruments held for trading purposes during the first three months of 2003 follows:

	Amount
	(millions)
Net unrealized gain at December 31, 2002	$111
Reclassification of contracts - adoption of EITF 02-03:
Non-derivative energy contracts	(90)
Derivative energy contracts, not held for trading purposes	(18)
	(108)
Contracts realized or otherwise settled during the period	36
Net unrealized gain at inception of contracts initiated during the period	-
Changes in valuation techniques	-
Other changes in fair value	71
Net unrealized gain at March 31, 2003	$110

The balance of net unrealized gains and losses recognized for the Company's energy-related derivative instruments held for trading purposes at March 31, 2003 is summarized in the following table based on the approach used to determine fair value and the contract settlement or delivery dates:

	Maturity Based on Contract Settlement or Delivery Date(s)
Source of Fair Value:	Less than 1 year	1-2 years	2-3 years	3-5 years	In Excess of 5 Years	Total
	(millions)
Actively quoted(1)	$63	$ 5	$10	-	-	$  78
Other external sources(2)	-	19	5	$7	$ 1	32
Models and other valuation techniques(3)	-	-	-	-	-	-
Total	$63	$24	$15	$7	$ 1	$110

(1) Exchange-traded and over-the-counter contracts.

(2) Values based on prices from over-the-counter broker activity and industry services and, where applicable, conventional option pricing models.
(3) Values based on the Company's estimate of future commodity prices when information from external sources is not available and use of internally-developed models, reflecting option pricing theory, discounted cash flow concepts, etc.

Delivery Segment

First Quarter 2003 Results

Delivery's net income contribution increased $17 million to $69 million for the first quarter ended March 31, 2003, as compared to the same period in 2002. The increase in net income primarily reflects a $45 million increase in operating revenue partially offset by a $10 million increase in operating expenses and a $15 million increase in income tax expense. Comparably colder temperatures in 2003 and customer growth contributed approximately $32 million and $4 million, respectively, to the $46 million increase in regulated electric sales. Partially offsetting these

PAGE 24

VIRGINIA ELECTRIC AND POWER COMPANY

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

increases in regulated electric sales revenue was a net decrease of $9 million due to other factors. A change in the allocation of the base rate revenues from Energy to Delivery increased Delivery's revenues by approximately $19
million. There were 27 percent more heating degree-days in the first quarter of 2003, as compared to 2002, and there were approximately 38,000 new electric customers added over the last twelve months.

Operations and maintenance expense increased $11 million, reflecting primarily an increase in general and administrative expenses and an increase in service restoration costs due to ice storms in the first quarter of 2003. Depreciation expense decreased by $3 million, reflecting primarily the effect of changes in the estimated useful lives of distribution property adopted in the second quarter of 2002. See Note 2 to the Consolidated Financial Statements for additional discussion of the change in estimated useful lives of the distribution property in 2002.

Corporate and Other

First Quarter 2003 Results

The change in the corporate segment's contribution to reported earnings is attributable primarily to the following items which impacted the first quarter of 2003, as compared to the same period last year: $8 million related to severance costs for workforce reductions; a $139 million after-tax gain, representing the cumulative effect of a change in accounting principle from adoption of SFAS No. 143; and a $55 million after-tax charge, representing the cumulative effect of a change in accounting principle from adoption of EITF Issue No. 02-03. For more information on the cumulative effect of the changes in accounting principle, see Note 3 to the Consolidated Financial Statements.

Liquidity and Capital Resources

The Company depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash flow from operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities and additional long-term debt financings.

Internal Sources of Liquidity

Cash flow provided by operating activities totaled approximately $666 million and $321 million during the three months ended March 31, 2003 and 2002, respectively. The Company's management believes that its operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and maintain current dividends payable to Dominion. As noted above, the Company uses a combination of short-term borrowings and sales of securities to fund capital requirements not covered by the timing or amounts of operating cash flows.

The Company's operations are subject to risks and uncertainties that may negatively impact cash flows from operations. See the discussion of such factors in Internal Sources of Liquidity in the MD&A of the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

External Sources of Liquidity

In the External Sources of Liquidity section of the MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002, the Company discussed its use of capital markets as well as the impact of credit ratings on the accessibility and costs of using these markets. In addition, the Company discussed various covenants present in the enabling agreements underlying the Company's debt. As of March 31, 2003, there have been no downgrades of the Company's credit ratings. In addition, there have been no changes to or events of default under the Company's debt covenants.

PAGE 25

VIRGINIA ELECTRIC AND POWER COMPANY

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

Long-term Debt

In February 2003, the Company issued $400 million aggregate principal amount of its 2003 Series A 4.75 percent senior notes due March 1, 2013. The Company used the cash proceeds for general corporate purposes, including the repayment of other debt.

In February 2003, the Company repaid $10 million of maturing medium-term notes.

Joint Credit Facilities

Dominion, Consolidated Natural Gas (CNG) and the Company are parties to 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. The Company expects to renew the 364-day revolving credit facility prior to its maturity in May 2003. These joint credit

facilities are used for working capital, as support for the combined commercial paper programs of Dominion, CNG and the Company and other general corporate purposes. The three-year facility can also be used to support up to $200 million of letters of credit. At March 31, 2003, total outstanding letters of credit supported by the three-year facility were $106 million, which were issued by Dominion on behalf of its other subsidiaries.

Short-term Debt

At March 31, 2003, net borrowings under the commercial paper program were $43 million, a decrease of $400 million from December 31, 2002. Commercial paper borrowings are used primarily to fund working capital requirements and may vary significantly during the course of the year depending upon the timing and amount of cash requirements not satisfied by cash provided from operations.

Borrowings from Parent

During the first quarter of 2003, unregulated subsidiaries of the Company repaid the $100 million that Dominion had advanced pursuant to a short-term demand note in 2002.

Amounts Available under Shelf Registrations

At March 31, 2003, the Company had $1.325 billion of available capacity under currently effective shelf registrations with the SEC that would permit the Company to issue debt and preferred securities to meet future capital requirements.

Investing Activities

During the three months ended March 31, 2003, investing activities resulted in a net cash outflow of $236 million. These activities included plant construction and other property expenditures of $199 million and nuclear fuel expenditures of $28 million. The plant expenditures related to generation-related projects totaled approximately $110 million and included costs related to environmental upgrades, nuclear reactor head replacement expenditures and other capital improvements. The plant expenditures related to transmission and distribution projects totaled approximately $82 million, reflecting routine capital improvements and expenditures associated with new connections. Other general and information technology projects totaled approximately $7 million. Investing activities also include $9 million of contributions to the Company's nuclear decommissioning trusts.

Contractual Obligations

As of March 31, 2003, other than scheduled maturities of new debt issued during the first quarter of 2003, there have been no significant changes to the contractual obligations disclosed in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

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VIRGINIA ELECTRIC AND POWER COMPANY

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

Future Issues

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 the Consolidated Financial Statements. This section should be read in conjunction with Future Issues and Outlook in MD&A in the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

Status of Electric Deregulation Legislation in Virginia

In an addendum to its status report on the development of a competitive retail market for electric generation within Virginia, the Virginia State Corporation Commission (Virginia Commission) recommended that state policymakers should decide promptly whether to proceed with or delay implementation of the Virginia Electric Utility Restructuring Act, in light of recent developments impacting electric industry restructuring in Virginia, including the Federal Energy Regulatory Commission's (FERC) issuance of a notice of proposed rule making on Standard Market Design. The Virginia General Assembly and Governor elected not to act on these recommendations.

In April 2003, Virginia enacted legislation that requires the Company to file an application with the Virginia Commission by July 1, 2003 to join a regional transmission organization (RTO) and delays entry into a RTO until on or after July 1, 2004. Subject to Virginia Commission approval, the Company would be required to transfer management and control of its electric transmission assets to a RTO by January 1, 2005.

Proposed Pilot Programs

In March 2003, the Company filed an application with the Virginia Commission for approval of three proposed new electric retail access pilot programs. The pilots will make available to competitive service providers up to 500 MW of load, with expected participation of more than 65,000 customers from a variety of customer classes. If approved by the Virginia Commission, the proposed pilots will run from January 1, 2004 through December 31, 2005. To encourage participation by competitive suppliers and customers, the Company has proposed a significant reduction in the wires charges applicable to the pilot programs in 2004 and 2005. The Virginia Commission issued a procedural order in April 2003 establishing a schedule for interested parties to file comments or to request a hearing.

RTO

See Status of Electric Deregulation Legislation in Virginia above regarding recently enacted Virginia legislation regarding entry into a RTO.

In December 2002, American Electric Power (AEP), Commonwealth Edison Company (ComEd), Dayton Power and Light Company (collectively, the New PJM Companies), PJM Interconnection, LLC (PJM) and the Company tendered a joint filing with FERC. The joint filing proposes to (1) include the New PJM Companies' transmission facilities within PJM functional control; (2) establish a transmission rate for the existing PJM region, the Company and the New PJM Companies; (3) adopt a transitional rate method to maintain transmission revenue for the Company and the New PJM Companies and (4) amend certain agreements on file with FERC concerning the PJM energy market, planning processes and system operations as related to the integration of the New PJM Companies into PJM.

In April 2003, FERC issued an order accepting AEP's and ComEd's proposal to transfer control of their respective transmission facilities to PJM and set a hearing for the proposed transmission rates which would be effective as of the date of the transfer. FERC also directed AEP and ComEd to recalculate and refile the proposed rates due to the rejection of the Company's filing noted below.

In April 2003, FERC issued an order rejecting the Company's proposed amendment to its open access transmission tariff to establish a transitional transmission rate method that would apply from the time AEP and ComEd would begin to participate under the PJM transmission tariff until the Company joins PJM.

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VIRGINIA ELECTRIC AND POWER COMPANY

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

Environmental Matters

As previously reported in Note 21 to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2002, the Company received a Notice of Violation in 2000 from the United States Environmental Protection Agency related to some specified construction projects at the Mt. Storm Power Station in West Virginia. Thereafter, New York State filed a suit against the Company alleging similar violations, and the suit was stayed. The Company reached an agreement in principle with the federal government and the state of New York to resolve the matter, and the states of Virginia, West Virginia, Connecticut and New Jersey joined the United States and the state of New York in seeking to reach a final agreement with the Company. A settlement agreement in the form of a proposed Consent Decree was agreed to on April 21, 2003, by the U.S. Department of Justice and the U.S. Environmental Protection Agency for the United States of America, by the states of Virginia, West Virginia, Connect icut, New Jersey and New York and by the Company. In accordance with the settlement, the United States filed an action in the Eastern District of Virginia against the Company and the Consent Decree was lodged with that court to settle that action. Virginia and West Virginia also filed complaints in intervention in the Virginia federal district court. The New York State federal district court action has been transferred to the Virginia federal district court and it is anticipated that, in addition to New York, Connecticut and New Jersey will join as plaintiffs in that proceeding. After an EPA public comment period, the Virginia federal district court will be asked to enter the Consent Decree finalizing the settlement and resolving the underlying actions, but retaining jurisdiction pursuant to the terms of the Consent Decree. The settlement is consistent with the previously reported agreement in principle and includes payment of a $5 million civil penalty, an obligation to fund $14 million for environmental pr ojects and a commitment to improve air quality under the Consent Decree estimated to involve expenditures of $1.2 billion. The Company has already incurred certain capital expenditures for environmental improvements at its coal-fired stations in Virginia and West Virginia and has committed to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree. As of March 31, 2003, the Company had accrued $18 million for the civil penalty and the funding of the environmental projects, substantially all of which was recorded in 2000.

Accounting Matters

Recently Issued Accounting Standards

On April 30, 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. See Note 4 to the Consolidated Financial Statements for a discussion of the impact of adopting this new accounting standard and information about other standard-setting activities.

Other Matters

In 2001, the Company filed application for 20-year license extensions with the Nuclear Regulatory Commission (NRC) for the North Anna and Surry units. The NRC renewed the Company's operating licenses for those plants in the first quarter of 2003. See Note 2 to the Consolidated Financial Statements for more information.

PAGE 28

VIRGINIA ELECTRIC AND POWER COMPANY

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK

The matters discussed in this Item may contain "forward-looking statements" as described in the introductory paragraphs under Part I, Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q. The reader's attention is directed to those paragraphs for discussion of various risks and uncertainties that may affect the future of the Company.

Market Rate Sensitive Instruments and Risk Management

The Company's financial instruments, commodity contracts and related derivative instruments are exposed to potential losses due to adverse changes in interest rates, equity security prices, foreign currency exchange rates, and commodity prices, as described below. Interest rate risk generally is related to the Company's outstanding debt. The Company is exposed to foreign exchange risk associated with purchases of certain nuclear fuel services denominated in foreign currencies. Commodity price risk is present in the Company's electric operations and energy marketing and trading operations due to the exposure to market shifts for prices received and paid for natural gas, electricity and other commodities. The Company uses derivative instruments to manage price risk exposures for these operations. The Company is exposed to equity price risk through various portfolios of equity securities.

The Company's sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10 percent unfavorable change in commodity prices, interest rates and foreign exchange rates.

Commodity Price Risk-Trading Activities

As part of its strategy to market energy and to manage related risks, the Company manages a portfolio of commodity-based financial derivative instruments held for trading purposes. These contracts are sensitive to changes in the prices of natural gas, electricity and certain other commodities. The Company uses established policies and procedures to manage the risks associated with these price fluctuations and uses various derivative instruments, such as futures, forwards, swaps and options, to mitigate risk by creating offsetting market positions. In addition, the Company seeks to use its generation capacity, when not needed to serve customers in its service territory, to satisfy commitments to sell energy.

A hypothetical 10 percent unfavorable change in commodity prices would have resulted in a decrease of approximately $50 million in the fair value of its commodity-based financial derivative contracts held for trading purposes as of March 31, 2003. A hypothetical 10 percent unfavorable change in commodity prices, as determined at December 31, 2002, would have resulted in a decrease of approximately $26 million in the fair value of its commodity-based financial derivative contracts held for trading purposes.

Interest Rate Risk

The Company manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. The Company also enters into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at both March 31, 2003 and December 31, 2002, the impact on annual earnings of a hypothetical 10 percent increase in interest rates would not be significant.

Foreign Exchange Risk

The Company manages its foreign exchange risk exposure associated with anticipated future purchases of nuclear fuel uranium enrichment services denominated in foreign currencies by utilizing currency forward contracts. As a result of holding these contracts as hedges, the Company's exposure to foreign currency risk is minimal. A hypothetical 10 percent unfavorable change in relevant foreign exchange rates would have resulted in a decrease of approximately $17 million in the fair value of currency forward contracts held by the Company at both March 31, 2003 and December 31, 2002.

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VIRGINIA ELECTRIC AND POWER COMPANY

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
(Continued)

Investment Price Risk

The Company is subject to investment price risk due to marketable equity securities held as investments in its nuclear decommissioning trusts. In accordance with current accounting standards, these marketable equity securities are reported on the balance sheet at fair value. The Company recognized net realized and unrealized losses on decommissioning trust investments of $28 million for the three-month period ended March 31, 2003 and $56 million for the year-ended December 31, 2002.

Dominion also sponsors employee pension and other postretirement benefit plans, in which the Company's employees participate, that hold investments in trusts to fund benefit payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in the Company's recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash to be contributed to the employee benefit plans.

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VIRGINIA ELECTRIC AND POWER COMPANY

ITEM 4. CONTROLS AND PROCEDURES

Senior management, including the Chief Executive Officers and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures during the month of April and in early May of 2003. Based on this evaluation process, the Chief Executive Officers 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 31

VIRGINIA ELECTRIC AND POWER 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 Dominion and its subsidiaries, 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 Future Issues in Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) for discussion on various regulatory proceedings to which the Company and its subsidiaries are a party.

In March 2003, Triad Energy Resources Corporation and other parties filed a class action antitrust suit against a number of defendants, including the Company and Cove Point LNG Limited Partnership, an affiliate of CNG, in the United States District Court for the District of Columbia. The complaint seeks compensatory damages for alleged violations of the Sherman Act and tortious interference with contractual and business relationships as a result of activities involving the storage and transportation of natural gas. No trial date has been set. The outcome of the proceeding, including an estimate as to any potential loss, cannot be predicted at this time.

In connection with the Notice of Violation received in 2000 from the Environmental Protection Agency related to some specified construction projects at the Mt. Storm Power Station in West Virginia, a settlement agreement in the form of a proposed Consent Decree was agreed to on April 21, 2003 by the U.S. government, the Company and the five states involved. See Environmental Matters in the MD&A of this Form 10-Q for further information relating to this development.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On April 25, 2003, by consent in lieu of a meeting, Dominion Resources, Inc., the sole holder of all the voting common stock of the Company, elected the following persons to serve as Directors: Thos. E. Capps, Thomas F. Farrell, II, and Thomas N. Chewning.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits:
	3.1	Restated Articles of Incorporation, as amended, as in effect on May 6, 1999, as amended December 6, 2002 (Exhibit 3.1, Form 10-K for the year ended December 31, 2002, File No. 1-2255, incorporated by reference).
	3.2	Bylaws, as amended, as in effect on April 28, 2000 (Exhibit 3, Form 10- Q for the period ended March 31, 2000, File No. 1-2255, incorporated by reference).
	10	Form of Settlement Agreement in a form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Dominion (filed herewith).
	12.1	Ratio of earnings to fixed charges (filed herewith).
	12.2	Ratio of earnings to fixed charges and preferred dividends (filed herewith).
	99.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

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VIRGINIA ELECTRIC AND POWER COMPANY
PART II. - OTHER INFORMATION

(a) Exhibits (continued):
	99.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
	99.3	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
	99.4	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
	99.5	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
	99.6	Condensed consolidated earnings statements (unaudited) (filed herewith).

(b) Reports on Form 8-K:
	1.	The Company filed a report on Form 8-K on February 23, 2003, relating to the sale of $400,000,000 aggregate principal amount of the Company's 2003 Series A 4.75% Senior Notes due 2013.
	2.	The Company filed a report on Form 8-K on May 9, 2003 relating to the segment realignment of its electric transmission operations.

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.

	VIRGINIA ELECTRIC AND POWER COMPANY Registrant
May 9, 2003	/s/ Steven A. Rogers
	Steven A. Rogers Vice President (Principal Accounting Officer)

CERTIFICATIONS

I, Thomas F. Farrell, II certify that:

1. I have reviewed this quarterly report on Form 10-Q of Virginia Electric and Power Company;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

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;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

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

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 9, 2003
	/s/ Thomas F. Farrell, II
	Thomas F. Farrell, II President and Chief Executive Officer

I, Jay L. Johnson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Virginia Electric and Power Company:

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

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;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

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

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 9, 2003
	/s/ Jay L. Johnson
	Jay L. Johnson President and Chief Executive Officer

I, Paul D. Koonce, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Virginia Electric and Power Company:

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

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;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

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

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 9, 2003
	/s/ Paul D. Koonce
	Paul D. Koonce Chief Executive Officer - Transmission

I, Mark F. McGettrick, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Virginia Electric and Power Company:

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

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;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

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

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 9, 2003
	/s/ Mark F. McGettrick
	Mark F. McGettrick President and Chief Executive Officer - Generation

I, G. Scott Hetzer, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Virginia Electric and Power Company:

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

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;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

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

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 9, 2003
	/s/ G. Scott Hetzer
	G. Scott Hetzer Senior Vice President and Treasurer (Principal Financial Officer)

EX-10

UNITED STATES DISTRICT COURT
EASTERN DISTRICT OF VIRGINIA

___________________________________
UNITED STATES OF AMERICA, STATE OF NEW YORK, STATE OF NEW JERSEY, STATE OF CONNECTICUT, COMMONWEALTH OF VIRGINIA STATE OF WEST VIRGINIA	)
	)
	)
	)
	)	CIVIL ACTION NO.
Plaintiffs,	)
	)
v.	) )
VIRGINIA ELECTRIC AND POWER COMPANY,	) )
	)
Defendant.	)
___________________________________	)

CONSENT DECREE

WHEREAS Plaintiff, the United States of America ("the United States"), on behalf of the United States Environmental Protection Agency ("EPA"), has filed a Complaint alleging that Defendant, Virginia Electric and Power Company ("VEPCO"), commenced construction of major modifications of major emitting facilities in violation of the Prevention of Significant Deterioration ("PSD") requirements at Part C of the Clean Air Act ("Act"), 42 U.S.C. Sections 7470-7492;

WHEREAS on April 24, 2000, EPA issued a Notice of Violation ("NOV") to VEPCO with respect to certain alleged violations of PSD;

WHEREAS Plaintiff, the State of New York, filed a complaint against VEPCO on July 20, 2000, alleging violations of the Act at VEPCO's Mount Storm Power Station located in northeastern West Virginia;

WHEREAS Plaintiff, the State of Connecticut, has issued VEPCO a notice of intent to sue, alleging violations of the Act and also has filed a complaint alleging violations of the Act at certain VEPCO electric generating units;

WHEREAS Plaintiff, the State of New Jersey, has issued to VEPCO a notice of intent to sue, alleging violations of the Act and also filed a complaint alleging violations of the Act at certain VEPCO electric generating units;

           WHEREAS Plaintiff, the Commonwealth of Virginia, is filing a Motion for Leave to Intervene and Complaint in Intervention alleging that VEPCO may have violated Virginia's air pollution regulations found at 9 VAC 50-80-1700, et seq., "Permits for Major Stationary Sources and Major Modifications Locating in Prevention of Significant Deterioration Areas," at one or more of its coal-fired generating units located in Virginia and that such violations may recur or other similar violations may occur in the future;

WHEREAS the Parties consent to intervention by the Commonwealth of Virginia;

            WHEREAS Plaintiff, the Commonwealth of Virginia, has a significant interest in this litigation by reason of its aforesaid Complaint as well as by reason of: (1) the fact that a significant portion of the relief provided by this Decree will involve facilities located within Virginia and regulated by the Commonwealth and no other State, and (2) the fact that such relief will directly impact the issuance to the affected facilities of permits under the Commonwealth's program approved pursuant to Title V of the Clean Air Act;

WHEREAS, Section 10.1-1186.4 of the Code of Virginia specifically authorizes the Attorney General of Virginia to seek to intervene in pending federal enforcement actions such as this one brought by the United States through the Environmental Protection Agency.

           WHEREAS Plaintiff, the State of West Virginia is filing a Motion for Leave to Intervene and Complaint in Intervention alleging that VEPCO may have violated West Virginia's air pollution regulations found at 45CAR14, "Permits for Construction and Major Modification of Major Stationary Sources of Air Pollution for the Prevention of Significant Deterioration," at one or more of its coal-fired generating units located in West Virginia and that such violations may recur or other similar violations may occur in the future;

WHEREAS the Parties consent to intervention by the State of West Virginia;

WHEREAS Plaintiff, the State of West Virginia, has a significant interest in this litigation by reason of its aforesaid Complaint as well as by reason of: (1) the fact that a significant portion of the relief provided by this Decree will involve facilities located within West Virginia and regulated by the State of West Virginia and no other State, and (2) the fact that such relief will directly impact the issuance to the affected facilities of permits under the West Virginia program approved pursuant to Title V of the Clean Air Act;

WHEREAS, Section 22-1-6 (d)(3) of the West Virginia Code specifically authorizes the Secretary of the West Virginia Department of Environmental Protection to enforce the statutes or rules which the Department is charged with enforcing.

WHEREAS VEPCO, a large electric utility, responded in a constructive way to Plaintiffs' notices of intent to sue and the NOV and expended significant time and effort to develop and agree to the terms of settlement embodied in this Decree;

WHEREAS VEPCO asserts that installation and operation of the pollution controls required by this Decree will result in emission reductions beyond current regulatory requirements;

WHEREAS the steam electric generating units at VEPCO's Mount Storm Power Station qualified for alternative emission limitations under 40 CFR Section 76.10 because VEPCO demonstrated under the applicable standard that they were not capable of meeting the emissions limitations otherwise applicable under the Clean Air Act's Acid Rain Nitrogen Oxides Emission Reduction Program;

WHEREAS Plaintiffs and VEPCO disagree fundamentally over the nature and scope of modifications that may be made to steam electric generating units without implicating the New Source Review requirements (including PSD) under the Act and its regulations;

WHEREAS nothing in this Decree resolves or is intended to resolve those disagreements;

WHEREAS VEPCO has advised the United States and the Plaintiff States that VEPCO has entered into this Consent Decree in reliance on the expectation that EPA will continue to enforce the modification provisions of the Act's New Source Review program in substantially the same manner as set forth in the complaints filed herein;

WHEREAS VEPCO has been advised that the United States retains all of its discretion concerning whether and how to enforce the Clean Air Act against any person, nothing in this Consent Decree is intended to predict or impose enforcement activities on EPA or the United States, and that the obligations of VEPCO under this Consent Decree are not conditional on subsequent enforcement activities of the Federal government;

WHEREAS the Plaintiffs allege that their Complaints state claims upon which the relief can be granted against VEPCO under Sections 113, 167, or 304 of the Act, 42 U.S.C. Sections 7413, 7477, or 7604;

WHEREAS VEPCO has not answered any of the Complaints in light of the settlement memorialized in this Decree;

WHEREAS VEPCO has denied and continues to deny the violations alleged in the NOV and the Complaints; maintains that it has been and remains in compliance with the Act and is not liable for civil penalties or injunctive relief; and states that it is agreeing to the obligations imposed by this Decree solely to avoid the costs and uncertainties of litigation and to improve the environment;

WHEREAS VEPCO intends to comply with any applicable Federal or State Implementation Plans that result from the NO_x SIP Call (63 Fed. Reg. 57356 (1998)) separate and apart from the obligations imposed by this Decree, and such Federal or State Implementation Plans that may ultimately result from the NO_x SIP Call are not intended to be enforceable under this Decree, and instead are enforceable in accordance with their own terms and the laws pertaining to them;

WHEREAS the Plaintiffs and VEPCO agree that settlement of these actions is fair, reasonable, and in the best interest of the Parties and the public, and that entry of this Consent Decree without further litigation is the most appropriate means of resolving this matter;

WHEREAS the Plaintiffs and VEPCO have consented to entry of this Decree without the trial or other litigation of any allegation in the complaints;

NOW THEREFORE, without any admission of fact or law, and without any admission of the violations alleged in the Complaints or NOV, it is hereby ORDERED, ADJUDGED, AND DECREED as follows:

I. JURISDICTION AND VENUE

1. Solely for purposes of entry and enforcement of this Decree, the parties agree that this Court has jurisdiction over the subject matter herein and over the Parties consenting hereto pursuant to 28 U.S.C. Sections 1331, 1345, 1355, and 1367 and pursuant to Sections 113 and 167 of the Act, 42 U.S.C. Sections 7413 and 7477, and also pursuant to 42 U.S.C. Section7604(a). Venue is proper under Section 113(b) of the Act, 42 U.S.C. Section 7413(b), and under 28 U.S.C. Section 1391(b) and (c). VEPCO consents to and shall not challenge entry of this Consent Decree or this Court's jurisdiction to enter and enforce this Consent Decree. Except as expressly provided for herein, this Consent Decree shall not create any rights in any party other than the Plaintiffs and VEPCO. VEPCO consents to entry of this Decree without further notice.

II. APPLICABILITY

2. Scope. The provisions of this Consent Decree shall apply to and be binding upon - consistent with Section XXVIII ("Sale or Transfers of Ownership Interests") - the Plaintiffs and VEPCO, including VEPCO's officers, employees, and agents solely in their capacities as such. Unless otherwise specified, each requirement on VEPCO under this Consent Decree shall become effective thirty days after entry of this Decree.
3. Notice to those Performing Decree-Mandated Work. VEPCO shall provide a copy of this Decree to all vendors, suppliers, consultants, or contractors performing any of the work described in Sections IV through IX. Notwithstanding any retention of contractors, subcontractors or agents to perform any work required under this Consent Decree, VEPCO shall be responsible for ensuring that all work is performed in accordance with the requirements of this Consent Decree. In any action to enforce this Consent Decree, VEPCO shall not assert as a defense the failure of its employees, servants, agents, or contractors to take actions necessary to comply with this Decree, unless VEPCO establishes that such failure is delayed or excused under Section XXVI ("Force Majeure").

III. DEFINITIONS

4. Every term expressly defined by this Section shall have the meaning given that term herein. Every other term used in this Decree that is also a term used under the Act or the regulations implementing the Act shall mean in this Decree what such terms mean under the Act or those regulations.

5. "30-Day Rolling Average Emission Rate" for a Unit means and is calculated by (A) summing the total pounds of the pollutant in question emitted from the Unit during an Operating Day and the previous twenty-nine (29) Operating Days; (B) summing the total heat input to the Unit in mmBTU during the Operating Day and during the previous twenty-nine (29) Operating Days; and (C) dividing the total number of pounds of pollutants emitted during the thirty (30) Operating Days by the total heat input during the thirty (30) Operating Days, and converting the resulting value to lbs/mmBTU. A new 30-Day Rolling Average Emission Rate shall be calculated for each new Operating Day. In calculating all 30-Day Rolling Average Emission Rates VEPCO :

A. shall include all emissions and BTUs commencing from the time the Unit is synchronized with a utility electric distribution system through the time that the Unit ceases to combust fossil fuel and the fire is out in the boiler, except as provided by Subparagraph B, C, or D;
B. shall use the methodologies and procedures set forth in 40 C.F.R. Part 75;
C. may exclude emissions of NOx and BTUs occurring during the fifth and subsequent Cold Start Up Period(s) that occur in any 30-Day period if inclusion of such emissions would result in a violation of any applicable 30-Day Rolling Average Emissions Rate, and if VEPCO has installed, operated and maintained the SCR in question in accordance with manufacturers' specifications and good engineering practices. A "Cold Start Up Period" occurs whenever there has been no fire in the boiler of a Unit (no combustion of any fossil fuel) for a period of six hours or more. The emissions to be excluded during the fifth and subsequent Cold Start Up Period(s) shall be the less of (1) those NOx emissions emitted during the eight hour period commencing when the Unit is synchronized with a utility electric distribution system and concluding eight hours later or (2) those emitted prior to the time that the flue gas has achieved the SCR operational temperature as specified by the catalyst manufacturer; and
D. may exclude NOx emissions and BTUs occurring during any period of malfunction (as defined at 40 C.F.R. 60.2) of the SCR.

6. "30-Day Rolling Average Removal Efficiency" means the percent reduction in the SO₂ Emissions Rate achieved by a Unit's FGD over a 30 Operating Day period, as further described by the terms of this Decree.
7. "Air Quality Control Region" means a geographic area designated under Section 107(c) of the Act, 42 USC. Section 7407(c).

8. "Boiler Island" means a Unit's (A) fuel combustion system (including bunker, coal pulverizers, crusher, stoker, and fuel burners); (B) combustion air system; (C) steam generating system (firebox, boiler tubes, and walls); and (D) draft system (excluding the stack), all as further described in "Interpretation of Reconstruction," by John B. Rasnic U.S. EPA (November 25, 1986) and attachments thereto.
9. "Capital Expenditures" means all capital expenditures, as defined by Generally Accepted Accounting Principles (GAAP), as VEPCO applied GAAP to its Boiler Island expenditures for the calendar years 1995-2000. Excluded from "Capital Expenditure" is the cost of installing or upgrading pollution control devices and the cost of altering or replacing any portion of the Boiler Island if such alteration or replacement is required in accordance with good engineering practices to accomplish the installation or upgrading of a pollution control device to meet the requirements of this Decree.
10. "CEMS" or "Continuous Emission Monitoring System," for obligations involving NO_x and SO₂ under this Decree, shall mean "CEMS" as defined in 40 C.F.R. Section 72.2 and installed and maintained as required by 40 C.F.R. Part 75.
11. "Clean Air Act" or "Act" means the Clean Air Act, 42 U.S.C. Sections 7401-7671q, and its implementing regulations.
12. "Completed," when used in connection with Sections XI through XVII (Resolution of Certain Civil Claims) and with respect to a change or modification, means the time when the Unit subject to the change or modification has been returned to service and is capable of generating electricity.
13. "Connecticut" means the State of Connecticut.
14. "Consent Decree" or "Decree" means this Consent Decree and its Appendices A through C, which are incorporated by reference ( Appendix A -- "Coal-Fired Steam-Electric Generating Units Constituting the VEPCO System"; Appendix B -- "Consent Decree Reporting Form"; and Appendix C -- "Mitigation Projects that Shall be Completed Under this VEPCO Consent Decree").
15. "Defendant" means Virginia Electric and Power Company or VEPCO.
16. "Emission Rate" means the number of pounds of pollutant emitted per million BTU of heat input ("lb/mmBTU"), measured as required by this Consent Decree.
17. "EPA" means the United States Environmental Protection Agency.
18. "ESP" means electrostatic precipitator, a pollution control device for the reduction of PM.
19. "FGD" means a pollution control device that employs flue gas desulfurization technology to remove SO₂ from flue gas.
20. "Improved Unit" means, in the case of NOx, a VEPCO System Unit scheduled under this Decree to be equipped with SCR and, in the case of SO2, means a VEPCO System Unit scheduled under this Decree to be equipped with an FGD, or Possum Point Units 3 and 4 because of their conversion to natural gas, as listed in Appendix A of this Decree and any amendment thereto. A Unit may be an Improved Unit for one pollutant without being an Improved Unit for the other.
21. "KW" means a kilowatt, which is one thousand Watts or one thousandth of a megawatt (MW).
22. "lb/mmBTU" means the number of pounds of pollutant emitted per million British Thermal Units of heat input.
23. "MW" means megawatt or one million Watts.
24. "National Ambient Air Quality Standards" means national air quality standards promulgated pursuant to Section 109 of the Act, 42 U.S.C. Section 7409.
25. "New York" means the State of New York.
26. "New Jersey" means the State of New Jersey.
27. "NOV" means the Notice of Violation issued by EPA to VEPCO, dated April 24, 2000.
28. "NO_x" means oxides of nitrogen, as further described by the terms of this Decree.
29. "NSR" means New Source Review and refers generally to the Prevention of Significant Deterioration and Non-Attainment provisions of Parts C and D of Subchapter I of the Act.
30. "Operating Day" for a coal-fired Unit means any calendar day on which such a Unit burns fossil fuel.
31. "Other Unit" means any Unit of the VEPCO System that is not an Improved Unit for the pollutant in question. A Unit may be an Improved Unit for NOx and an Other Unit for SO2 and vice versa.
32. "Ozone Season" means the five-month period from May 1 through September 30 of any year after 2004. For the year 2004, "Ozone Season" means the period from May 31, 2004, through September 30, 2004.
33. "Paragraph" means a provision of this Decree preceded by an Arabic number.
34. "Parties" means VEPCO, the United States, Virginia, West Virginia, New York, New Jersey, and Connecticut.
35. "Plaintiffs" means the United States, New York, New Jersey, Connecticut, Virginia, and West Virginia.
36. "PM" means total particulate matter as further described by the terms of this Decree.
37. "PM CEM" or "PM Continuous Emission Monitor" means equipment that samples, analyses, measures, and provides PM emissions data -- by readings taken at frequent intervals -- and makes an electronic or paper record of the PM emissions measured.
38. "Pollution Control Upgrade Analysis" means the technical study, analysis, review, and selection of control technology recommendations (including an emission rate or removal efficiency) performed in connection with an application for a federal PSD permit, taking into account the characteristics of the existing facility. Except as otherwise provided in this Consent Decree, such study, analysis, review, and selection of recommendations shall be carried out in accordance with applicable federal and state regulations and guidance describing the process and analysis for determining Best Available Control Technology (BACT), as that term is defined in 40 C.F.R. Section 52.21(b)(12), including, without limitation, the December 1, 1987 EPA Memorandum from J. Craig Potter, Assistant Administrator for Air and Radiation, regarding Improving New Source Review (NSR) Implementation. Nothing in this Decree shall be construed either to: (A) alter the force and effect of statements known as or characterized as "guidanc e" or (B) permit the process or result of a "Pollution Control Upgrade Analysis" to be considered BACT for any purpose under the Act.
39. "ppm" means parts per million by dry volume, corrected to 15 percent O₂.
40. "Project Dollars" means VEPCO's properly documented internal and external costs incurred in carrying out the dollar-limited projects identified in Section XXI ("Mitigation Projects") and Appendix C, as determined in accordance with Generally Accepted Accounting Principles (GAAP) (subject to review by the Plaintiffs), and provided that such costs comply with the Project Dollars and other requirements for such expenditures and payments set forth in Section XXI ("Mitigation Projects") and Appendix C.
41. "PSD" means Prevention of Significant Deterioration, as that term is understood under Part C of Subchapter I of the Clean Air Act, 42 U.S.C. Sections 7470 - 7492 and 40 C.F.R. Part 52.
42. "PSD Increment" means the maximum allowable increase in a pollutant's concentration over the baseline concentration within the meaning of Section 163 of the Act, 42 U.S.C. Section 7473 and 40 C.F.R. Section 51.166(c).
43. "SCR" means a pollution control device that employs selective catalytic reduction to remove NO_x from flue gas.
44. "Seasonal System-Wide Emission Rate" for a pollutant means the total pounds of the pollutant emitted by the VEPCO System during the period from May 1 through September 30 of each calendar year, divided by the total heat input (in mmBTU) to the VEPCO System during the period from May 1 through September 30 of the same calendar year. VEPCO shall calculate the Seasonal System-Wide Emission Rates from hourly CEMS data collected and analyzed in compliance with the 40 C.F.R. Part 75.
45. "Section" means paragraphs of this Decree collected under a capitalized heading that is preceded by a Roman Numeral.
46. "SO₂" means sulfur dioxide, as described further by the terms of this Decree.
47. "SO₂ Allowance" means the same as the definition of "allowance" found at 42 U.S.C. Section 7651a(3): "an authorization, allocated to an affected unit, by the Administrator [of EPA] under [Subchapter IV of the Act] to emit, during or after a specified calendar year, one ton of sulfur dioxide."
48. "Subparagraph" means any subdivision of a Paragraph identified by any number or letter.
49. "System-Wide Annual Emission Rate" for a pollutant shall mean the total pounds of the pollutant emitted by the VEPCO System during a calendar year, divided by the total heat input (in mmBTU) to the VEPCO System during the same calendar year. VEPCO shall calculate and analyze the System-Wide Annual Emission Rates from hourly CEM data collected in compliance with 40 C.F.R. Part 75.
50. "Title V Permit" means each permit required under Subchapter V of the Clean Air Act, 42 U.S.C. Section 7661, et seq., for each electric generating plant that includes one or more Units that are part of the VEPCO System.
51. "VEPCO System" means all the Units listed here and described further in Appendix A: Bremo Power Station Units 3 and 4 (in Fluvanna County, Virginia); Chesapeake Energy Center Units 1, 2, 3, and 4 (near Chesapeake, Virginia); Chesterfield Power Station Units 3, 4, 5, and 6 (in Chesterfield County, Virginia); Clover Power Station Units 1 and 2 (in Halifax County, Virginia); Mount Storm Power Station Units 1, 2, and 3 (in northeastern West Virginia); North Branch Power Station Units 1A and 1B (in northeastern West Virginia); Possum Point Power Station Units 3 and 4 (in Northern Virginia, about twenty-five miles south of Washington, D.C.); and Yorktown Power Station Units 1 and 2 (in Yorktown, Virginia).
52. "Virginia" means the Commonwealth of Virginia.
53. "Watt" means a unit of power equal to one joule per second.
54. "West Virginia" means the State of West Virginia.
55. "Unit" means a generator, the steam turbine that drives the generator, the boiler that produces the steam for the steam turbine, the equipment necessary to operate the generator, turbine and boiler, and all ancillary equipment, including pollution control equipment or systems necessary for the production of electricity.

IV. NO_x EMISSION REDUCTIONS AND CONTROLS

56. Unit-Specific SCR Installations and Performance Requirements. VEPCO shall install an SCR on each Unit listed below, no later than the date specified below and, commencing on that date and continuing thereafter, operate each SCR to meet a 30-Day Rolling Average Emission Rate for NO_x of 0.100 lb/mmBTU for each listed Unit, except that VEPCO shall meet a 30-Day Rolling Average Emissions Rate of 0.110 lb/mmBTU for Mount Storm Units 1, 2 and 3:

Units on Which VEPCO Shall Install an SCR	Latest Date by which VEPCO Must: (A) Complete Installation of Fully Operational SCR, and (B) Start Operation that Meets 30-Day Rolling Average NOx Emission Rate
Mount Storm Unit 1	January 1, 2008
Mount Storm Unit 2	January 1, 2008
Mount Storm Unit 3	January 1, 2008
Chesterfield Unit 4	January 1, 2013
Chesterfield Unit 5	January 1, 2012
Chesterfield Unit 6	January 1, 2011
Chesapeake Energy Center Unit 3	January 1, 2013
Chesapeake Energy Center Unit 4	January 1, 2013

57. VEPCO also shall use best efforts to operate each SCR required under this Decree whenever VEPCO operates the Unit served by the SCR, in accordance with manufacturers' specifications, good engineering practices, and VEPCO's operational and maintenance needs.

58. Year-Round Operation of SCRs. Beginning on January 1, 2008, and continuing thereafter, in accordance with the SCR installation schedule provided for in Paragraph 56 (Unit specific SCR Installation and Performance Requirements), every VEPCO System Unit served by an SCR required pursuant to Paragraph 56 shall operate year-round and achieve and maintain a NO_x 30-Day Rolling Average Emission Rate of no more than 0.100 lb/mmBTU, except that Mount Storm Units 1, 2 and 3 shall achieve a NOx 30-Day Rolling Average Emission Rate of no more than 0.110 lb/mmBTU.

59. VEPCO System: Interim Control of NO_x Emissions: 2004 through 2007. Commencing in 2004 and ending on December 31, 2007, VEPCO shall control NO_x emissions under the provisions of either Subparagraph (A) or (B) of this Paragraph. VEPCO may elect to comply with either Subparagraph in any calendar year and may change its election from year to year. VEPCO shall notify the Parties in writing on or before January 1 of each calendar year of whether it elects to comply with Subparagraph (A) or Subparagraph (B) for that year. If VEPCO fails to provide such notice by January 1 of any year, the last elected option for the prior calendar year shall be deemed to apply, and, if none, Subparagraph (B) shall be deemed to apply for such year. The requirements of this Paragraph shall terminate on December 31, 2007:

(A) During the following three time periods, VEPCO shall control emissions of NO_x by operating SCRs on VEPCO System Units of at least the mega-wattage capacities specified and shall achieve a 30-Day Rolling Average Emission Rate for NOx of no greater than 0.100 lb/mmBTU at each such Unit, except that Mount Storm Units 1, 2 and 3 shall achieve a NOx 30-Day Rolling Average Emission Rate of no more than 0.110 lb/mmBTU, as follows:

(i) May 31, 2004, through April 30, 2005: Operate SCR on combined capacity of at least 375 MW on any combination of VEPCO System Units, but at least one Unit so controlled shall be at the Chesterfield Station.

(ii) May 1, 2005, through April 30, 2006: Operate SCR on combined capacity of at least 875 MW on any combination of VEPCO System Units, but at least one-half of the 875 MW so controlled shall be from a Unit or Units at the Chesterfield and/or Mt. Storm Stations.

(iii) May 1, 2006, through December 31, 2007: Operate SCR on combined capacity of at least 1,450 MW on any combination of VEPCO System Units, but at least one-half of the 1,450 MW so controlled shall be from a Unit or Units at the Chesterfield and/or Mt. Storm Stations; or

(B) During the Ozone Seasons of the years 2004 through 2007, actual NO_x emissions from the VEPCO System shall not exceed a Seasonal System Wide Emission Rate greater than 0.150 lb/mmBTU. VEPCO's compliance with this limit shall be achieved, in part, by operating an SCR at the Mt. Storm and Chesterfield Stations.

60. VEPCO System NO_x Limits 2003 and thereafter: Declining, System-Wide Tonnage Caps. Actual, total emissions of NO_x from the VEPCO System in each calendar year, beginning in 2003 and continuing thereafter, shall not exceed the number of tons specified below:

Calendar Year	Total Permissible NOx Emissions (in Tons) from VEPCO System
2003	104,000
2004	95,000
2005	90,000
2006	83,000
2007	81,000
2008	63,000
2009	63,000
2010	63,000
2011	54,000
2012	50,000
2013 and each year thereafter	30,250

61. VEPCO System-Wide, Annual Average NO_x Emission Rate. Commencing January 1, 2013, and continuing thereafter, actual NO_x emissions from the VEPCO System shall not exceed a System-Wide Annual Average Emission Rate of 0.150 lb/mmBTU.
62. NOx Measurement and Calculation Procedures and Methods. In determining emission rates for NO_x, VEPCO shall use those applicable monitoring or reference methods specified in 40 C.F.R. Part 75.
63. Evaluation of NOx Emission Limitations Based Upon Performance Testing. At any time after September 30, 2004, VEPCO may submit to the Plaintiffs a proposed revision to the applicable 30-Day Rolling Average Emissions Rate for NOx on any VEPCO System Unit equipped with SCR and subject to a 30-Day Rolling Average Emission Rate. To make a successful petition, VEPCO must demonstrate that it cannot consistently achieve the Decree-mandated NOx emissions rate for the Unit in question, considering all relevant information, including but not limited to the past performance of the SCR, reasonable measures to achieve the designed level of performance of the SCR in question, the performance of other NOx controls installed at the unit, and the operational history of the Unit. VEPCO shall include in such proposal an alternative 30-Day Rolling Average Emissions Rate. VEPCO also shall retain a qualified contractor to assist in the performance and completion of the petition for an alternate 30-Day Rolling Averag e Emissions Rate for NOx. VEPCO shall deliver with each submission all pertinent documents and data that support or were considered in preparing such submission. If the Plaintiffs disapprove the revised emission rate, such disagreement is subject to Section XXVII ("Dispute Resolution"). VEPCO shall make any submission for any Unit under this Paragraph no later than fifteen months after the compliance date specified for that unit in Paragraph 56 ("Unit-Specific SCR Installations and Performance Requirements").

V. SO₂ EMISSION REDUCTIONS AND CONTROLS

64. Installation and Construction of, and Improvements to, plus Removal Efficiencies Required on, FGDs Serving: Clover Units 1 and 2, Mount Storm Units 1, 2, and 3, and Chesterfield Units 5 and 6. VEPCO shall construct or improve -- as applicable -- FGDs for each Unit listed below, to meet or exceed the Removal Efficiencies for SO₂ specified below, in accordance with the schedules set out below. VEPCO shall operate each FGD so that each Unit shall continuously meet or exceed the SO₂ removal efficiency specified for it, as a 30-Day Rolling Average Removal Efficiency, during the time periods described (Phases I and II):

Plant Name and Unit Number	Duration of Phase I Removal Efficiency Requirement	Phase I Minimum 30-Day Rolling Average Removal Efficiency (%)	Duration of Phase II Removal Efficiency Requirement	Phase II Minimum 30-Day Rolling Average Removal Efficiency (%)
Clover Unit 1	Meet 30-Day Rolling Average by 09/01/ 2003 and thereafter	95.0	Same as Phase I	Same as Phase I
Clover Unit 2	Meet 30-Day Rolling Average by 09/01/ 2003 and thereafter	95.0	Same as Phase I	Same as Phase I
Mt. Storm Unit 1	Meet 30-Day Rolling Average by 09/01/ 2003 and through 12/31/04 through Dec. 31, 2004	93.0	Jan. 1, 2005, and thereafter	95.0
Mt. Storm Unit 2	Meet 30-Day Rolling Average by 09/01/ 2003 and through 12/31/04	93.0	Jan. 1, 2005, and thereafter	95.0
Mt. Storm Unit 3	Meet 30-Day Rolling Average by 09/01/ 2003 and through 12/31/04	93.0	Jan. 1, 2005, and thereafter	95.0
Chesterfield Unit 5	Oct. 12, 2012, and thereafter	95.0	Same as Phase I	Same a Phase I
Chesterfield Unit 6	Jan. 1, 2010, and thereafter	95.0	Same as Phase I	Same as Phase I

65. Chesterfield FGD Construction. This Decree does not require VEPCO to begin: (A) physical construction on or begin significant equipment procurement for the FGD for Chesterfield Unit 6 prior to July 1, 2008, or (B) physical construction on or significant equipment procurement for the FGD for Chesterfield Unit 5 before January 1, 2010.
66. Option of Compliance with an Emission Rate after an FGD Demonstrates SO₂ 30-Day Rolling Average Removal Efficiency of at least 95.0%. Once a Unit (and its FGD) listed in Paragraph 64 demonstrates at least 95 percent removal efficiency for SO₂ for at least 180 consecutive days of operation without FGD bypass as specified in Paragraph 67 (omitting days on which the Unit did not combust fossil fuel) on a 30-Day Rolling Average basis, then VEPCO -- at its option and with written, prior notice to the Plaintiffs -- shall meet the following emission rate for SO₂ rather than the 30-Day Rolling Average Removal Efficiency specified in Paragraph 64:

Plant and Unit Eligible to Make 180-Day Demonstration	Maximum SO2 30-Day Rolling Average Emission Rate VEPCO shall meet in Lieu of 95.0%, 30-Day Rolling Average Removal Efficiency (lb/mmBTU)
Clover Unit 1	0.130
Clover Unit 2	0.130
Chesterfield Unit 5	0.130
Chesterfield Unit 6	0.130
Mount Storm Unit 1	0.150
Mount Storm Unit 2	0.150
Mount Storm Unit 3	0.150

67. Interim Mitigation of Mount Storm SO₂ Emissions While FGDs are Improved. Notwithstanding the requirement to meet a specific percent removal or emission rate at Mount Storm Units 1, 2, or 3, in limited circumstances, VEPCO may operate such Units without meeting required Removal Efficiencies or Emission Rates in the case of FGD scrubber outages or downtime of the FGD scrubber serving each such Unit, if such operation complies with the following requirements. For this Paragraph, FGD outage or downtime "day" shall consist of a 24-hour block period commencing in the hour the FGD ceases to operate, and continuing in successive 24-hour periods until the hour the FGD is placed back into operation. Any period of less than 24 hours of FGD downtime shall count as a full "day". For the FGD serving Unit 3, because it has two separately operating absorber vessels, outage or downtime may be measured in "1/2 day" (12-hour) increments - one for each absorber - but otherwise on the same basis as a "d ay" is counted for outage or downtime on the FGDs serving Units 1 and 2.

(A) In any calendar year from 2003 through 2004 for Mount Storm Unit 3, and in any calendar year from 2003 through 2004 for Mount Storm Units 1 and 2, VEPCO may operate Mount Storm Units 1, 2, or 3 in the case of outage or downtime of the FGD serving such Unit, if all of the following conditions are satisfied:

(i) VEPCO does not operate Mount Storm Units 1, 2, or 3 during FGD outages or downtime on more than thirty (30) "days", or any part thereof, in any calendar year; in the case of Mount Storm Unit 3, operation during an outage or downtime in either of the two FGD absorber vessels serving the Unit shall count as operation during a "1/2" day of FGD outage or downtime;

(ii) All other available VEPCO System Units on-line at the Mount Storm Station and Clover Power Station are dispatched ahead of the Mount Storm Unit experiencing the FGD outage or downtime;

(iii) For each of the first twenty (20) "days" in a calendar year, or part thereof, that a Unit operates under this Paragraph VEPCO surrenders to EPA (using the procedure Section VI, Paragraph 72) one SO₂ Allowance, in addition to any surrender or possession of allowances required under Title IV or under any other provision of this Consent Decree, for each ton of SO₂ actually emitted in excess of the SO₂ emissions that would have occurred if coal containing 1.90 lb/mmBTU sulfur had been burned; and

(iv) For each "day", or part thereof, that a Unit operates under this Paragraph beyond twenty (20) "days" in a calendar year, VEPCO shall surrender to EPA (using the procedure in Section VI, Paragraph 72) one SO₂ Allowance, in addition to any surrender or possession of allowances required under Title IV or under any other provision of this Consent Decree, for each ton of SO₂ actually emitted in excess of SO₂ emissions that would have occurred if coal containing 1.70 lb/mmBTU sulfur had been burned.

(B) In any calendar year from 2005 through 2007, VEPCO may operate Mount Storm Units 1, 2, or 3 in the case of FGD outage or downtime, if all of the following conditions are satisfied:

(i) VEPCO does not operate Mount Storm Units 1 or 2 during FGD outages or downtime on more than thirty (30) "days", or any part thereof, in any calendar year; and in the case of Mount Storm Unit 3, operation during an outage or downtime in either one of the two FGD absorber vessels serving the Unit shall count as operation during "1/2" day of FGD outage or downtime;
(ii) All other available VEPCO System Units on-line at the Mount Storm Station and Clover Power Station are dispatched ahead of the Mount Storm Unit experiencing the FGD outage or downtime;

(iii) For each of the first ten (10) "days", or part thereof, in a calendar year that a Unit operates under this Paragraph VEPCO surrenders to EPA (using the procedure in Section VI, Paragraph 72) one SO₂ Allowance, in addition to any surrender or possession of allowances required under Title IV or under any other provision of this Consent Decree, for each ton of SO₂ actually emitted in excess of the SO₂ emissions that would have occurred if coal containing 1.90 lb/mmBTU sulfur had been burned;

(iv) For each day that a Unit operates under this Paragraph from the eleventh through the twentieth "days", or part thereof, in a calendar year, VEPCO shall surrender to EPA (using the procedure in Section VI, Paragraph 72) one SO₂ Allowance, in addition to any surrender or possession of allowances required under Title IV or under any other provision of this Consent Decree, for each of the tons of SO₂ actually emitted that equal the mass emissions difference between actual emissions and those that would have occurred if coal containing 1.70 lb/mmBTU sulfur had been used.; and

(v) For each day that a Unit operates under this Paragraph beyond twenty (20) "days", or part thereof, in a calendar year, VEPCO shall surrender to EPA (using the procedure Section VI, Paragraph 72) one SO₂ Allowance, in addition to any surrender or possession of allowances required under Title IV or under any other provision of this Consent Decree, for each ton of SO₂ actually emitted in excess of SO₂ emissions that would have occurred if coal containing 1.50 lb/mmBTU sulfur had been burned;

(C) In any calendar year from 2008 through 2012, VEPCO may operate Mount Storm Units 1, 2, or 3 in the case of FGD outages or downtime, if all of the following conditions are satisfied:

(i) VEPCO does not operate Mount Storm Units 1, 2, or 3 during FGD outages or downtime on more than ten (10) "days", or part thereof, in any calendar year; in the case of Mount Storm Unit 3, operation during an outage or downtime in either of the two FGD absorber vessels serving the Unit shall count as "1/2" day of operation during an FGD outage or downtime;

(ii) All other available VEPCO System Units on-line at the Mount Storm Station and Clover Station are dispatched ahead of the Mount Storm Unit experiencing the FGD outage or downtime; and

(iii) VEPCO surrenders to EPA (using the procedure of Section VI, Paragraph 72) one SO₂ Allowance, in addition to any surrender or possession of allowances required under Title IV or under any other provision of this Consent Decree, for each ton of SO₂ actually emitted in excess of SO₂ emissions that would have occurred if coal with 1.50 lb/mmBTU sulfur had been burned.

68. Calculating 30-Day Rolling Average Removal Efficiency of a VEPCO System FGD. The SO₂ 30-Day Rolling Average Removal Efficiency for a VEPCO System FGD shall be obtained and calculated using SO₂ CEMS data in compliance with 40 CFR Part 75 (from both the inlet and outlet of the control device) by subtracting the outlet 30-Day Rolling Average Emission Rate from the inlet 30-Day Rolling Average Emission Rate on each day the boiler operates, dividing that difference by the inlet 30-Day Rolling Average Emission Rate, and then multiplying by 100. A new 30-Day Rolling Average Removal Efficiency shall be calculated for each new Operating Day. In the case of FGDs serving Chesterfield Units 5 and 6 or Mount Storm Units 1, 2, or 3, if any flue gas emissions containing SO₂ did not pass through the inlet of the Unit's scrubber on a day when the Unit operated, VEPCO must account for, report on, and include any such emissions in calculating the FGD Removal Efficiency for that d ay and for every 30-Day Rolling Average of which that day is a part.
69. Commencing within 30 days after lodging of this Decree, VEPCO shall use best efforts to operate each such FGD at all times the Unit the FGD serves is in operation, provided that such FGD system can be operated consistent with manufacturers' specifications, good engineering practices and VEPCO's operational and maintenance needs. In calculating a 30-Day Rolling Average Removal Efficiency or a 30-Day Rolling Average Emission Rate for a Mount Storm Unit, VEPCO need not include SO₂ emitted by Unit while its FGD is shut down in compliance with Paragraph 67 ("Interim Mitigation of Mount Storm SO₂ Emissions While FGDs are Improved").
70. SO₂ Measurement Methods. VEPCO shall conduct all emissions monitoring for SO₂ in compliance with 40 C.F.R. Part 75.

VI. ANNUAL SURRENDER OF SO₂ ALLOWANCES

71. Annual Surrender. On or before March 31 of every year beginning in 2013 and continuing thereafter, VEPCO shall surrender 45,000 SO₂ Allowances. In each year, this surrender of SO₂ Allowances may be made either directly to EPA or by first transferring the SO₂ Allowances to another person in the manner provided for by this Decree.
72. Surrender Directly to EPA. If VEPCO elects to make an annual surrender directly to EPA, VEPCO shall, on or before March 31, 2013, and on or before March 31 of each year thereafter, submit SO₂ Allowance transfer request forms to EPA's Office of Air and Radiation's Clean Air Markets Division directing the transfer of 45,000 SO₂ Allowances held or controlled by VEPCO to the EPA Enforcement Surrender Account or to any other EPA Account to which the EPA may direct. As part of submitting these transfer requests, VEPCO shall irrevocably authorize the transfer of these Allowances and VEPCO shall also identify - by name of account and any applicable serial or other identification numbers or plant names - the source and location of the Allowances being surrendered, as well as any information required by the transfer request form.
73. Alternate Method of Surrender. If VEPCO elects to make an annual surrender of SO₂ Allowances to a person other than EPA, VEPCO shall include a description of such transfer in the next report submitted to Plaintiffs pursuant to Section XIX ("Periodic Reporting") of this Consent Decree. Such report shall: (A) provide the identity of the third-party recipient(s) of the SO₂ Allowances and a listing of the serial numbers of the transferred allowances; (B) include a certificate in compliance with Section XIX from the third-party recipient(s) stating that it (they) will not sell, trade, or otherwise exchange any of the allowances and will not use any of the allowances to meet any obligation imposed by any environmental law. No later than the next periodic report due 12 months after the first report of the transfer, VEPCO shall include in the Section XIX reports to Plaintiffs a statement that the third-party recipient(s) permanently surrendered the allowances to EPA within one ye ar after VEPCO transferred the allowances to the third-party recipient(s). VEPCO shall not have finally complied with the allowance surrender requirements of this Paragraph until all third-party recipient(s) shall have actually surrendered the transferred allowances to EPA.
74. Changes to Decree-Mandated SO₂ Allowance Surrenders Beginning in 2013, and every year thereafter:

(A) If changes in Title IV of the Act or it implementing regulations decrease the number of SO₂ Allowances that are allocated to the VEPCO System Units for the year 2013 or any year thereafter, or if other applicable law either: (A) awards fewer than 127,363 SO₂ Allowances to the VEPCO System or (B) directs non-reusable surrender of SO₂ Allowances by VEPCO, then the number of SO₂ Allowances that VEPCO must surrender in such a year under this Section shall decrease by the same amount;

(B) If changes to Title IV of the Act or its implementing regulations result in (i) a reduction of SO₂ Allowances to the VEPCO System and (ii) any amount of SO₂ Allowances being auctioned-off, and the national SO₂ Allowance pool reflects a nationwide reduction in SO₂ Allowances of less than 35.6% from the 2010 national pool, then the number of SO₂ Allowances that VEPCO must surrender in such year under this Section of this Decree shall decrease as follows:

45,000 - (127,363 x the percent reduction of the National pool)

Thus, if the national pool of SO₂ Allowances is reduced by greater than 35.6% from the 2010 national pool of SO₂ allowances, then VEPCO is not required to surrender any SO₂ Allowances under this Decree. But in no event shall VEPCO keep in excess of 82,363 SO₂ Allowances allocated in any year after 2012 to the VEPCO System.

(C) If changes to Title IV of the Act or its implementing regulations result in an increase of SO₂ Allowances to VEPCO, then VEPCO's annual obligation to surrender such Allowances under this Decree shall increase by the amount of such increase.

75. Use of SO₂ Allowances Related to VEPCO System Units Scheduled for FGDs under the Decree. For all SO₂ Allowances allocated to Mount Storm Unit 1 on or after January 1, 2003, Mount Storm Unit 2 on or after January 1, 2003, Chesterfield Unit 5 on or after October 1, 2012, and Chesterfield Unit 6 on or after January 1, 2010, VEPCO may use such SO₂ Allowances only to (A) meet the SO₂ Allowance surrender requirements established for the VEPCO System under this Decree; (B) meet the limits imposed on VEPCO under Title IV of the Act; or (C) meet any federal or state future emission reduction programs that use or rely on Title IV SO₂ Allowances for compliance, in whole or in part. However, if VEPCO operates a FGD serving Mount Storm Unit 1, Mount Storm Unit 2, Chesterfield Unit 5, or Chesterfield Unit 6 either: (A) earlier than required by a provision of this Decree or (B) at a 30-Day Rolling Average Removal Efficiency greater than, or a 30-Day Roll ing Average Emissions Rate less than that required by this Decree, then VEPCO may use for any lawful purpose SO₂ Allowances equal to the number of tons of SO₂ that VEPCO removed from the emission of those Units in excess of the SO₂ tonnage reductions required by this Decree, so long as VEPCO timely reports such use under Section XIX.
76. Other Limits on Use of SO₂ Allowances. VEPCO may not use the same SO₂ Allowance more than once. VEPCO may not use the SO₂ Allowances surrendered under this Section for any other purpose, including, but not limited to, any sale or trade of such Allowances for use by any person other than VEPCO or by any Unit not part of the VEPCO System, except as provided by Paragraph 73 ("Alternate Method of Surrender"). Other than the limits stated in this Decree on use of SO₂ Allowances or limits imposed by law, this Decree imposes no other limits on how VEPCO may use SO₂ Allowances.
77. No Entitlement Created. This Consent Decree does not entitle VEPCO to any allocation of SO₂ Allowances under the Act.

VII. PM EMISSION REDUCTIONS AND CONTROLS

78. Use of Existing PM Pollution Control Equipment. Commencing within 30 days after lodging of this Decree, VEPCO shall operate each ESP and baghouse within the VEPCO System to maximize PM emission reductions through the procedures established in this Paragraph. VEPCO shall (A) commence operation no later than two hours after commencement of combustion of any amount of coal in the controlled System Unit, except that this requirement shall apply to Bremo Power Station Units 3 and 4 commencing two hours after cessation of oil injection to the boiler, and provided that, for all ESP-equipped Units, "combustion of any amount of coal" shall not include combustion of coal that is the result of clearing out a Unit's coal mills as the Unit is returned to service; (B) fully energize each available portion of each ESP, except those ESP fields that have been out of service since at least January 1, 2000, consistent with manufacturers' specifications, the operational design of the Unit, and good engineerin g practices, and repair such fields that go out of service consistent with the requirements of this Paragraph; (C) maintain power levels delivered to the ESPs, consistent with manufacturers' specifications, the operational design of the Unit, and good engineering practices; and (D) continuously operate each ESP and baghouse in compliance with manufacturers' specifications, the operational design of the Unit, and good engineering practices. Whenever any element of any ESP that has been in service at any time since January 1, 2000 fails, does not perform in accordance with manufacturers' specifications and good engineering practices, or does not operate in accordance with the standards set forth in this Paragraph, VEPCO shall use best efforts to repair the element no later than the next available Unit outage appropriate to the repair task. The requirements of this Paragraph do not apply to Possum Point Units 3 and 4 until January 1, 2004, and do not apply at all when those Units burn natural gas.
79. ESP and Baghouse Optimization Studies and Recommendations. VEPCO shall complete an optimization study, in accordance with the schedule below, for each VEPCO System Unit served by an ESP or baghouse (except Possum Point Units 3 and 4, in light of their conversion to natural gas), which shall recommend: the best available maintenance, repair, and operating practices that will optimize ESP or baghouse availability and performance in accordance with manufacturers' specifications, the operational design of the Unit, and good engineering practices. These studies shall consider any ESP elements not in service prior to January 1, 2000, to the extent changes to such elements may be required to meet a PM Emission Rate of 0.030 lb/mmBTU. Any operating practices or procedures developed and approved under this Paragraph shall become a part of the standard specified in (D) of Paragraph 78 ("Use of Existing PM Pollution Control Equipment"), above, and shall be implemented in compliance with that Paragraph. V EPCO shall retain a qualified contractor to assist in the performance and completion of each study. VEPCO shall submit each completed study to the United States for review and approval. (The United States will consult with the other Plaintiffs before completing such review). VEPCO shall implement the study's recommendations within 90 days (or any longer time period approved by the United States) after receipt of approval by the United States. If VEPCO seeks more than 90 days to implement the recommendations contained in the study, then VEPCO shall include, as part of the study, the reasons why more than 90 days are necessary to implement the recommendations, e.g., the need to order or install parts or equipment, retain specialized expertise, or carry out training exercises. VEPCO shall maintain each ESP and baghouse as required by the study's recommendations and shall supplement the ESP operational standard in (D) of Paragraph 78 to include any operational elements of the study and its recommendations. The s chedule for completion and submission to the United States of the optimization studies shall be as follows:

Number and Choice of VEPCO System Units on Which VEPCO Shall Complete and Submit Optimization Studies	Number of Months After Lodging of the Decree that VEPCO Shall Submit Optimizations Studies to the U.S.
Four Units (including at least one Unit at Mount Storm or Chesterfield)	12 Months
Three More Units (including at least two at any one or more of the following VEPCO stations - Mount Storm, Chesterfield, and Bremo, if not already done)	24 Months
Two More Units (including at least two located at any one or more of the following VEPCO stations - Mount Storm, Chesterfield, and Bremo, if not already done)	36 Months
Two More Units	48 Months
Two More Units	60 Months
All Other Units	72 Months

80. Alternative to Pollution Control Upgrade Analysis. Within 270 days after VEPCO receives the United States' approval of the ESP optimization study for a VEPCO System Unit, VEPCO may elect to achieve for any Unit the objectives of, and thereby avoid, the Pollution Control Upgrade Analysis otherwise required by this Section by certifying to the United States, in writing, that: (A) the ESP shall continue to be operated and maintained in compliance with the approved optimization plan, pursuant to Paragraphs 78 and 79 of this Section, respectively, and (B) that the enforceable PM emission limit for this Unit shall be 0.030 lb/mmBTU, either commencing immediately or on and after the date required by this Decree for completion of FGD installations or improvements at that Unit (or after installation of any other FGD system VEPCO chooses to install at a Unit prior to 2013). Otherwise, VEPCO shall comply with Paragraph 82 (Pollution Control Upgrade Analysis, Construction of PM Controls, Compliance with N ew Emission Rate"), below.
81. PM Emission Rate Determination. The methods specified in this Paragraph shall be the reference methods for determining PM Emission Rates along with any other method approved by EPA under its authority to establish or approve such methods. The PM Emission Rates established under Paragraph 80 of this Section shall not apply during periods of "startup" and "shutdown" or during periods of control equipment or Unit malfunction, if the malfunction meets the requirements of the Force Majeure Section of this Consent Decree. Periods of "startup" shall not exceed two hours after any amount of coal is combusted (except that for Bremo Power Station Units 3 and 4, this two-hour period begins upon cessation of injection of oil into the boiler). Periods of "shutdown" shall only commence when the Unit ceases burning any amount of coal (or in the case of Bremo Power Station Units 3 and 4, when any oil is introduced into the boiler). Coal shall not be deemed to be combusted if it is burned as a result of cleari ng out a Unit's coal mills as the Unit is returned to service. The reference methods for determining PM Emission Rates shall be those specified in 40 C.F.R. Part 60, Appendix A, Method 5 or Method 17, using annual stack tests. VEPCO shall calculate PM Emission rates from the annual stack tests in accordance with 40 C.F.R. 60.8(f) and 40 C.F.R. 60.48a(b). The annual stack-testing requirement of this Paragraph shall be conducted as described in Paragraph 95 and may be satisfied by: (A) any annual stack tests VEPCO may conduct pursuant to its permits or applicable regulations from the States of Virginia and West Virginia if such tests employ reference test methods allowed under this Decree, or (B) installation and operation of PM CEMs required under this Decree.
82. Pollution Control Upgrade Analysis of PM, Construction of PM Controls, Compliance with New Emission Rate. For each VEPCO System Unit served by an ESP -- other than Possum Point Units 3 and 4 and those Units that meet the requirements of Paragraph 80 ("Alternative to Pollution Control Upgrade Analysis") -- VEPCO shall complete a Pollution Control Upgrade Analysis and shall deliver the Analysis and supporting documentation to the United States for review and approval (after consultation with the other Plaintiffs). Notwithstanding the definition of Pollution Control Upgrade Analysis (Paragraph 38), VEPCO shall not be required to consider in this Analysis: (A) the replacement of any existing ESP with a new ESP, scrubber, or baghouse, or (B) the installation of any supplemental pollution control device similar in cost to a replacement ESP, scrubber, or baghouse (on a total dollar-per-ton-of-pollution-removed basis).
83. VEPCO shall retain a qualified contractor to assist in the performance and completion of each Pollution Control Upgrade Analysis. Within one year of the United States' approval of the work and recommendation(s) made in the Analysis (or within a longer period of time properly sought by VEPCO and approved by the United States), VEPCO shall complete all recommendation(s). If VEPCO seeks more than one year from the date of the United States' approval of the Analysis to complete the work and recommendations called for by the Analysis, VEPCO must state the amount of additional time required and the reasons why additional time is necessary. Thereafter, VEPCO shall operate each ESP in compliance with the work and recommendation(s), including compliance with the specified Emission Rate. The schedule for completion and submission to the United States of the Pollution Control Upgrade Analyses for each Unit subject to this Paragraph shall be 12 months after the United States approves the ESP optimization study f or each Unit pursuant to Paragraph 79 (unless VEPCO has elected to use the alternative to the Pollution Control Upgrade Analysis under Paragraph 80 for the Unit).
84. Performance Testing of Equipment Required by Pollution Control Upgrade Analysis. Between 6 and 12 months after VEPCO completes installation of the equipment called for by each approved Pollution Control Upgrade Analysis, VEPCO shall conduct a performance test demonstration to ensure that the approved PM emission limitation set forth in the Analysis can be consistently achieved in practice, including all requirements pertaining to proper operation and maintenance of control equipment. If the performance demonstration shows that the approved control equipment cannot consistently meet the required PM emission limitation, VEPCO shall revise the Pollution Control Upgrade Analysis and resubmit it to the United States for review and approval of an alternative emissions limitation.
85. Installation and Operation of PM CEMs. VEPCO shall install, calibrate, operate, and maintain PM CEMs, as specified below. Each PM CEM shall be comprised of a continuous particle mass monitor measuring particulate matter concentration, directly or indirectly, on an hourly average basis and a diluent monitor used to convert results to units of lb/mmBTU. VEPCO may select any type of PM CEMS that meets the requirements of this Consent Decree. VEPCO shall maintain, in an electronic database, the hourly average emission values of all PM CEMS in lb/mmBTU. During Unit startups, VEPCO shall begin operating the PM CEMs in accordance with the standards set out in Paragraph 78(A) ("Use of Existing PM Pollution Control Equipment"), and VEPCO shall thereafter use reasonable efforts to keep each PM CEM running and producing data whenever any Unit served by the PM CEM is operating. VEPCO shall submit to EPA for review and approval a plan to install, calibrate and operate each PM CEM. VEPCO shall thereafter op erate each PM CEM in accordance with the approved plan.
86. Installation of PM CEMs - First Round (Three Units). On or before December 1, 2003, VEPCO shall designate which three VEPCO System Units will have PM CEMs installed, in accordance with this Paragraph. No later than 12 months after entry of this Decree (or a longer time period approved by the United States, not to exceed 18 months after entry of this Decree) VEPCO shall install, calibrate, and commence operation of the following:

1. PM CEMs in the stacks that service at least two of the following VEPCO System Units: Mount Storm Units 1, 2, and 3, and Clover Units 1 and 2; and
2. at least one additional PM CEM at any other ESP-equipped Unit in the VEPCO System, as selected by VEPCO.

If VEPCO seeks more than 12 months after entry of the Decree to complete installation and calibration of the PM CEMs, then VEPCO shall include a full explanation of the reasons why it requires more than 12 months after entry of the Decree to complete installation and calibration.

87. Consultation Before the First Round of PM CEMs. Prior to installing any PM CEMs, VEPCO and the United States shall meet, consult, and agree to adequate mechanisms for treating potential emission limitation exceedances that may occur during installation and calibration periods of the PM CEMs that may exceed applicable PM emission limitations. VEPCO and the United States shall invite the States of Virginia and West Virginia to participate in these discussions.

88. Option for Consultation Both Before and After Installation of the First or Second Round of PM CEMs. Either before the first or second round of PM CEMs installations, or after such PM CEMs are installed and producing data, or both, the United States and VEPCO shall meet, upon the request of either, to examine further the data that may or may not be generated by the PM CEMs. This issue should be addressed in light of the regulatory or permit-based mass emission limit set for the Unit before it was equipped with a PM CEM or any PM emission limitation established or to be established under this Section of the Decree, and the parties should take appropriate and acceptable actions to address any issues concerning periodic short term Unit process and control device upsets and/or averaging periods. In the event VEPCO or the United States call for such a meeting, the United States and VEPCO shall invite the States of Virginia and West Virginia to participate.

89. Demonstration that PM CEMs Are Infeasible. No earlier than 2 years after VEPCO has installed the first round of PM CEMs, VEPCO may attempt to demonstrate that it is infeasible to continue operating PM CEMs. As part of such demonstration, VEPCO shall submit an alternative PM monitoring plan for review and approval by the United States. The plan shall explain the basis for stopping operation of the PM CEMs and propose an alternative-monitoring plan. If the United States disapproves the alternative PM monitoring plan, or if the United States rejects VEPCO's claim that it is infeasible to continue operating PM CEMs, such disagreement is subject to Section XXVII ("Dispute Resolution").

90. "Infeasible to Continue Operating PM CEMs" - Standard. Operation of a PM CEM shall be considered "infeasible" if, by way of example, the PM CEMS: (A) cannot be kept in proper condition for sufficient periods of time to produce reliable, adequate, or useful data; or (B) VEPCO demonstrates that recurring, chronic, or unusual equipment adjustment or servicing needs in relation to other types of continuous emission monitors cannot be resolved through reasonable expenditures of resources; or (C) chronic and difficult Unit operation issues cannot be resolved through reasonable expenditure of resources; or (D) the data produced by the CEM cannot be used to assess PM emissions from the Unit or performance of the Unit's control devices. If the United States determines that VEPCO has demonstrated infeasibility pursuant to this Paragraph, VEPCO shall be entitled to discontinue operation of and remove the PM CEMs.

91 PM CEM Operations Will Continue During Dispute Resolution or Proposals for Alternative Monitoring. Until the United States approves an alternative monitoring plan or until the conclusion of any proceeding under Section XXVII ("Dispute Resolution"), VEPCO shall continue operating the PM CEMs. If EPA has not issued a decision regarding an alternative monitoring plan within 90 days VEPCO may initiate action under the Dispute Resolution provisions (Section XXVII) under this Consent Decree.

92. Installation and Operation of PM CEMs - Second Round (6 Units). Unless VEPCO has been allowed to cease operation of the PM CEMs under Paragraph 89 ("Demonstration that PM CEMs Are Infeasible"), then VEPCO shall install, calibrate, and commence operation of PM CEMs that serve at least 6 more Units. In selecting the VEPCO System Units to receive PM CEMs under this second round, VEPCO must assure that Mount Storm Units 1, 2, and 3 and Clover Units 1 and 2 all receive PM CEMs if they have not already received PM CEMs under the first round. VEPCO may select the other VEPCO System Units to receive the required PM CEMs. The options for consultation regarding first round PM CEMs under Paragraphs 87 and 88 shall also be available for second round PM CEMs. VEPCO shall install PM CEMs that serve two VEPCO System Units in each of the years 2007, 2008, and 2009 under this second round of PM CEMs.

93. Common Stacks. Installation of a PM CEM on Mount Storm Units 1 and 2 or on Yorktown Units 1 and 2 shall count as installation of PM CEMs on 2 units in recognition of the common stack that serves these Units. VEPCO and the United States shall agree in writing on the method for apportioning emissions to the Units served by common stacks.

94. Data Use. Data from PM CEMs shall be used by VEPCO, at minimum, to monitor progress in reducing PM emissions. Nothing in this Consent Decree is intended to or shall alter or waive any applicable law (including, but not limited to, any defense, entitlements, challenges, or clarifications related to the Credible Evidence Rule (62 Fed. Reg. 8314 (Feb. 27, 1997))) concerning the use of data for any purpose under the Act, generated either by the reference methods specified herein or otherwise.

95. Other Testing and Reporting Requirements. Commencing in 2004, VEPCO shall conduct a stack test for PM on each stack servicing each Unit in the VEPCO System (excluding Possum Point Units 3 and 4 in 2004, and in any subsequent year in which such Units have not burned coal). Such PM stack testing shall be conducted at least once per every four successive "QA Operating Quarters" (as defined in 40 C.F.R. Section 72.2) and the results of such testing shall be submitted to the Plaintiffs as part of the periodic reporting under Section XIX ("Periodic Reporting") and Appendix B. Following installation of each PM CEM, VEPCO shall include all data recorded by PM CEMs, including submission in electronic format, if available, in the reports required by Section XIX.

VIII. POSSUM POINT UNITS 3 & 4:
FUEL CONVERSION, INSTALLATION OF CONTROLS

96. Fuel Conversion. VEPCO shall cease all combustion of coal at Possum Point Units 3 and 4 prior to May 1, 2003, in preparation for the conversion of Possum Point Units 3 and 4 to operate on natural gas, and shall not operate these Units again until that fuel conversion is complete and the Units are firing natural gas. VEPCO shall continuously operate such equipment to control NOx emissions in compliance with State permitting requirements. VEPCO also shall limit the combined emissions from Possum Point Units 3 and 4 to 219 tons of NOx in any 365 days, rolled daily, and determined as follows: Add the total NOX emissions from Possum Point Units 3 and 4 on any given day, occurring after entry of this Decree, to the total NOX emissions from those two Units for the preceding 364 consecutive days occurring after entry of the Decree; the sum of those emissions may never exceed 219 tons. If VEPCO exceeds this 219-ton limit, VEPCO shall install and operate SCR at BACT levels within 3 years of the excee dance at either Yorktown Unit 1 (173 MW), or Yorktown Unit 2 (183 MW), or Bremo Unit 4 (170 MW). VEPCO may select which of these Units receives the SCR so long as the following are true for the Unit:

1. An SCR is not required under regulatory requirements for the Unit;
2. VEPCO had not planned to install an SCR on such Unit to help comply with any requirement as of the day of exceedance at Possum Point; and
3. The Unit is not required to meet an emission rate that would call for installation of SCR.

If these conditions are not met for any of the three listed Units, then VEPCO shall install the required SCR at the next largest Unit (in MW) within the VEPCO System that meets the conditions of subparagraphs (A) through (C).

97. Return to Combustion of Coal After Gas Conversion. If VEPCO uses coal rather than natural gas to operate Possum Point Units 3 or 4 on or after May 1, 2003, VEPCO shall install controls on such Unit(s) and meet the following requirements for NO_x, SO₂, and PM emissions, on or after May 1, 2003:

(A) For NO_x, the more stringent of: (i) a 30-Day Rolling Average Emission Rate of 0.100 lb/mmBTU or (ii) the NO_x emission rate that would be LAER at the time that VEPCO returns to firing Possum Point Units 3 or 4 with coal;

(B) For SO₂, a 30-Day Rolling Average Removal Efficiency of at least 95.0%; and

(C) For PM, an Emission Rate of no more than 0.030 lb/mmBTU.

98. Measurements At Possum Point. The applicable methods and rules specified in other portions of this Decree for measuring emission rates and removal efficiencies for NO_x, SO₂, and PM also apply to the emission standards, as applicable, established under Paragraph 96 and 97 ("Fuel Conversion" and "Return to Combustion of Coal After Gas Conversion") for Possum Point Units 3 and 4.

IX. INSTALLING ADDITIONAL CONTROLS ON VEPCO SYSTEM UNITS

99. If, prior to November 1, 2004, this Consent Decree is modified to require that VEPCO:

(A) Install additional NO_x or SO₂ pollution control devices on a VEPCO System Unit not scheduled for installation of such control device as part the original Decree;

(B) Commence full-time (year-round) operation of such control device no later than January 1, 2008; and

(C) Operate the control device and the Unit it serves in compliance with a performance standard of 0.100 lb/mmBTU 30-Day Rolling Average Emission Rate for NO_x or a 95.0% 30-Day Rolling Average Removal Efficiency for SO₂;

then the modification of the Consent Decree shall also provide that such Unit be treated as an Improved Unit as to the pollutant that has been controlled in compliance with this Section.

100. Reference Methods. The reference and monitoring methods specified in other portions of this Decree for measuring all emission rates and removal efficiencies for NO_x, SO₂, and PM also apply to the emission standards established under this Section.

X. PERMITS

101. Timely Application for Permits. Unless expressly stated otherwise in this Consent Decree, in any instance where otherwise applicable law or this Consent Decree require VEPCO to secure a permit to authorize constructing or operating any device under this Consent Decree, VEPCO shall make such application in a timely manner. Such applications shall be completed and submitted to the appropriate authorities to allow sufficient time for all legally required processing and review of the permit request. Failure to comply with this provision shall allow Plaintiffs to bar any use by VEPCO of Section XXVI ("Force Majeure") where a Force Majeure claim is based upon permitting delays.

102. New Source Review Permits. This Consent Decree shall not be construed to require VEPCO to apply for or obtain a permit pursuant to the New Source Review requirements of Parts C and D of Title I of the Act for any work performed by VEPCO within the scope of the resolution of claims provisions of Sections XI through XVII (Resolution of Certain Civil Claims).103.

103. Title V Permits . Whenever VEPCO applies for a Title V permit or a revision to such a permit, VEPCO shall send, at the same time, a copy of such application to each Plaintiff. Also, upon receiving a copy of any permit proposed for public comment as a result of such application, VEPCO shall promptly send a copy of such proposal to each Plaintiff, thereby allowing for timely participation in any public comment opportunity.

104. Title V Permits Enforceable on Their Own Terms. Notwithstanding the reference to Title V permits in this Decree, the enforcement of such permits shall be in accordance with their own terms and the Act. The Title V permits shall not be directly enforceable under this Decree, though any term or limit established by or under this Decree shall be enforceable under this Decree regardless of whether such term has or will become part of a Title V Permit, subject to the limits of Section XXX ("Conditional Termination of Enforcement, Continuation of Terms, and First Resort to Title V Permit").

105. Consent Decree Requirements To Be Proposed for Inclusion in Title V Permits. Whenever VEPCO applies for Title V Permit(s), or for amendment(s) to existing Title V Permit(s), for the purpose of including the requirements of this Decree in such permits, VEPCO shall include in such application all performance, operational, maintenance, and control technology requirements specified by or created under this Consent Decree, not only for particular Units in the VEPCO System but also for the VEPCO System itself - including, but not limited to, emission rates, removal efficiencies, allowance surrenders, limits on use of emission credits, and operation, maintenance and optimization requirements, unless otherwise limited by Sections XI through XVII. VEPCO shall notify all Plaintiffs of any applicable requirement within its Title V permit application that may be more stringent than the requirements of this Consent Decree.

106. Methods to be Used in Applying for Title V Permit Provisions Applicable to the VEPCO System. VEPCO shall include provisions in any Title V permit application(s) submitted in accordance with Paragraph 105 ("Consent Decree Requirements To Be Proposed for Inclusion in Title V Permits") that comply with this Consent Decree's NO_x VEPCO System Declining Tonnage Cap (Section IV, Paragraph 60), the VEPCO System-Wide Annual Average Emission Rate for NO_x (Section IV, Paragraph 61), and the Annual Surrender of SO₂ Allowances from the VEPCO System (Section VI, Paragraphs 71). In making such application, VEPCO shall use either the provisions listed below or any other method agreed to in advance by written stipulation of all the Parties and filed with this Court:

(A) For the VEPCO System declining NO_x cap in Section IV, Paragraph 61 ("VEPCO System NO_x Limits 2002 and thereafter: Declining, System-Wide Tonnage Caps"), each Unit in the VEPCO System shall be limited in perpetuity to a specified portion of the NO_x annual emissions cap that ultimately descends to 30,250 tons, provided the total of the VEPCO System declining tonnage caps for NO_x submitted for inclusion in the Title V permits shall be no greater for any year than the tonnage specified for each calendar year for the VEPCO System). The NO_x emission tons shall be allocated to each Unit within the VEPCO System. No Unit shall exceed its allocation except that VEPCO can trade NOx emissions tons between Units within the VEPCO System in order to comply with any given Unit-specific allocation. Compliance with the NO_x Annual System-Wide Annual Average Emissions cap shall be determined each year by whether each Unit holds a sufficient numbe r of NO_x emission tons allocated to it in the Title V permit, or acquired by it through trades with other Units in the VEPCO System, to cover the Unit's actual, annual NO_x emissions; and

(B) For the System-Wide, Annual Average NO_x Emissions Rate specified in Section IV, Paragraph 61, ("VEPCO System-Wide, Annual Average NO_x Emission Rate") VEPCO shall prepare a VEPCO System-Wide NO_x emissions BTU-weighted averaging plan for all the Units in the VEPCO System, and in doing so, shall use all the appropriate methods and procedures specified at 40 C.F.R. Section 76.11 in preparing such a plan. As part of that plan, VEPCO shall prepare an "alternative contemporaneous allowable annual emissions limitation" (in lb/mmBTU) for each Unit in the VEPCO System, as described by 40 C.F.R. Section 76.11. After this allocation and establishment of an "alternative contemporaneous allowable annual emissions limitation," VEPCO's compliance with Paragraph 61 ("VEPCO System-Wide, Annual Average NO_x Emission Rate") shall be determined in the manner described by 40 C.F.R. Section 76.11, as applicable, and shall be based on whether each Unit meets the applicable "alternative contemporaneous allowable annual emissions limitation" for the NO_x emissions BTU weighted averaging plan; provided, however, that if any Unit(s) does not meet such emissions limitation, such Unit(s) shall still be in compliance if VEPCO shows that all the Units in the emissions averaging plan, in aggregate, do not exceed the BTU-weighted NO_x System-Wide Emissions Rate; and

(C) For the Annual Surrender of SO₂ Allowances required by Section VI, the annual SO₂ Allowance surrender requirement of 45,000 SO₂ Allowances shall either be divided up and allocated to specific Units of the VEPCO System or assigned to a single VEPCO System Unit - as VEPCO elects.

XI. RESOLUTION OF CERTAIN CIVIL CLAIMS OF THE UNITED STATES.

107. Claims Based on Modifications Occurring Before the Lodging of Decree. Entry of this Decree shall resolve all civil claims of the United States under either: (i) Parts C or D of Subchapter I of the Clean Air Act or (ii) 40 C.F.R. Section 60.14, that arose from any modification commenced at any VEPCO System Unit prior to the date of lodging of this Decree, including but not limited to, those modifications alleged in the U.S. Complaint in this civil action or in the EPA NOV issued to VEPCO on April 24, 2000.

108. Claims Based on Modifications after the Lodging of Decree. Entry of this Decree also shall resolve all civil claims of the United States for pollutants regulated under Parts C or D of Subchapter I of the Clean Air Act and regulations promulgated as of the date of the lodging of this Decree, where such claims are based on a modification completed before December 31, 2015 and:

A. commenced at any VEPCO System Unit after lodging of this Decree or

B. that this Consent Decree expressly directs VEPCO to undertake.

The term "modification" as used in this Paragraph shall have the meaning that term is given under the Clean Air Act statute as it existed on the date of lodging of this Decree.

109. Reopener. The resolution of the civil claims of the United States provided by this Section is subject to the provisions of Section XII.

XII. REOPENING OF U.S. CIVIL CLAIMS RESOLVED BY SECTION XI

110. Bases for Pursuing Resolved Claims Across VEPCO System. If VEPCO:

(A) Violates Paragraph 59(A) or (B) (VEPCO System-Wide, Interim Control of NOX Emissions, 2004 through 2007); or

(B) Violates Paragraph 60 (VEPCO System-Wide NOX Tonnage Limits 2003 and thereafter: Declining, System-Wide Tonnage Caps); or

(C) Violates Paragraph 61 (VEPCO System-Wide Average NOX Emission Rate) in any calendar year (or ozone season, as applicable); or

(D) Fails by more than ninety days to complete installation of and commence timely year-round operation of any SCR or FGD required by Paragraphs 56 or 64 or Sections VIII or IX; or

(E) Fails to limit VEPCO System SO2 emissions to 203,693 tons or less in each calendar year starting with 2005 and thereafter;

then the United States may pursue any claims at any VEPCO System Unit otherwise resolved under Section XI, where the modification(s) on which such claim is based was commenced, under way, or completed within five years preceding the violation or failure specified in items (A) through (E) above, unless such modification was undertaken at an Improved Unit and commenced prior to the date of lodging of this Consent Decree.

111. Other Units. The resolution of claims of United States in Section XI shall not apply to claims arising from modifications at Other Units commenced less than five years prior to the occurrence of one or more of the following:

(A) a modification or (collection of modifications) commenced after lodging of this Decree at such Other Unit, individually (or collectively) increase the maximum hourly emission rate for such Unit for the relevant pollutant (NOx or SO2) as measured by 40 C.F.R. Section 60.14(b) and (h); or

(B) the aggregate of all Capital Expenditures made at such Other Unit exceed $125/KW on the Unit's Boiler Island (based on the Maximum Dependable Capacity numbers in the North American Electric Reliability Council's Generating Availability Database for the year 2002) during any of the following five-year periods: January 1, 2001, through December 31, 2005; January 1, 2006, through December 31, 2010; January 1, 2011, through December 31, 2015. (Capital Expenditures shall be measured in calendar year 2000 constant dollars, as adjusted by the McGraw-Hill Engineering News-Record Construction Cost Index); or

(C) modification(s) commenced after lodging of this Decree resulting in emissions increase(s) of the relevant pollutant that actually occurred from any such Other Unit, where such increase(s):

(1) present by themselves or in combination with other emissions or sources "an imminent and substantial endangerment" within the meaning of Section 303 of the Act, 42 U.S.C. Section 7603; or

(2) cause or contribute to violation of a National Ambient Air Quality Standard in any Air Quality Control Area that is in attainment with that NAAQS; or

(3) cause or contribute to violation of a PSD increment; or

(4) cause or contribute to any adverse impact on any formally recognized air quality and related values in any Class I area.

112. Solely for purposes of Subparagraph 111(C ), above: (i) the determination of whether emissions increase(s) of the relevant pollutant actually occurred at the Unit must take into account any emissions changes relevant to the modeling domain that have occurred or will occur under this Decree at other VEPCO System Units; and (ii) an emissions increase shall not be deemed to have actually occurred unless annual emissions of the relevant pollutant from all VEPCO System Units at the plant at which such Unit is located (and treating Mount Storm and North Branch as a single plant for this purpose) have exceeded such plant's emissions of that pollutant after the lodging of this Consent Decree, as specified below:

Plant	SO2 Annual Emissions (tons)	NOX Annual Emissions (tons)
Bremo	13,463	4,755
Chesapeake	35,923	10,657
Chesterfield	75,330	15,858
Clover	Improved	10,076
Mt. Storm / North Branch	19,992	40,188
Yorktown	26,755	5,066

113. Introduction of any new or changed National Ambient Air Quality Standard shall not, standing alone, provide the showing needed under Subparagraph 111(C) (1)-(4) to pursue any claim resolved under Section XI.

114. Fuel Limit. The resolution of claims provided by Section XI shall not apply to any modification commenced on a Unit within five years prior to the date on which VEPCO:

(A) fires such Unit with any fuel or fuel mix that is either prohibited by applicable state law or that is not otherwise authorized by the relevant state; or

(B) increases the current (as of February 1, 2003) coal contracting bid specification or contract specifications that limit fuel sulfur content in securing coal for a Unit, as summarized in Appendix A. This Paragraph does not apply to VEPCO's use of: (i) a fuel or fuel mix specifically called for by this Decree, if any, or (ii) any coal in any coal-fired Unit regardless of the fuel's sulfur content, so long as such use occurs after the Unit is being served by an FGD or other control equipment that can maintain 95.0% Removal Efficiency for SO2, on a 30-day, rolling average basis.

115. Improved Units. The resolution of claims provided by Section XI shall not apply to a modification (or collection of modifications), if commenced after the lodging of this Decree at an Improved Unit, that individually (or collectively) increase the maximum hourly emission rate of that Unit for NO_x or SO₂ (as measured by 40 C.F.R. Section 60.14 (b) and (h)) by more than ten percent (10%) of the maximum hourly emission rate for that Unit.

XIII. Resolution of Past Claims of New York, New Jersey, and Connecticut

116. The States of New York, New Jersey, and Connecticut agree that this Decree resolves all of the following civil claims that have been or could have been brought against VEPCO for violations at Units at Mount Storm, Chesterfield or Possum Point prior to the lodging of this Decree:

(A) The Prevention of Significant Deterioration or Non- Attainment provisions of Parts C and D of the Clean Air Act, 42 U.S.C. Section 7401 et seq. and related state provisions; and(B) 40 C.F.R. Section 60.1.

XIV. RESOLUTION OF CIVIL CLAIMS OF THE COMMONWEALTH OF VIRGINIA.

117. Claims Based on Modifications Occurring Before the Lodging of Decree. Subject to the specific limitations in this Section, entry of this Decree shall resolve all civil and administrative claims of the Commonwealth of Virginia that arose from any modification (physical change or change in the method of operation, including construction of any air pollution control project at any VEPCO System Unit) under applicable federal statutes (Section 7410 (a)(2)(C), Part C or D of Subchapter I of the Clean Air Act or 40 CFR Section 60.14) or applicable state regulations (Article 6 (9 VAC 5-80-1100 et seq.), Article 8 (9 VAC 5-80-1700 et seq.) or Article 9 (9 VAC 5-80-2000 et seq.) of Part II of 9 VAC 5 Chapter 80, and provisions of 9 VAC 5, Chapter 50, that are equivalent to 40 C.F.R. Section 60.14(a)), and, as to the state regulations, all applicable predecessor regulations. This Paragraph shall apply to any modification commenced at any VEPCO System Unit located in the Commonwealth prior to the dat e of lodging of this Decree.

118. Claims Based on Modifications after the Lodging of Decree. Subject to the specific limitations in this Section, entry of this Decree shall also resolve all civil and administrative claims of the Commonwealth of Virginia arising from any modification (physical change or change in the method of operation, including construction of any air pollution control project at any VEPCO system Unit) under applicable federal statutes (Section 7410 (a)(2)(C), Part C or D of Subchapter I of the Clean Air Act) or applicable state regulations (Article 6 (9 VAC 5-80-1100 et seq.), Article 8 (9 VAC 5-80-1700 et seq.) or Article 9 (9 VAC 5-80-2000 et seq.) of Part II of 9 VAC 5 Chapter 80 and any successor regulations). This Paragraph shall apply to any modification at any VEPCO System Unit located in the Commonwealth commenced on or after lodging of this Decree that is completed before December 31, 2015, or are those that this Consent Decree expressly directs VEPCO to undertake.

119. Reopener. The resolution of the civil claims of the Commonwealth of Virginia provided by this Section is subject to the provisions of Section XV.

120. General. Each term used in Paragraph 118 that is also a term used under the Clean Air Act shall mean what such term means under the Act as it existed on the date of lodging of this Decree.

121. Commonwealth's Authority Regarding NAAQS Exceedances. Nothing in this Section shall be construed to affect the Commonwealth's authority under applicable federal statutes and applicable state regulations to impose appropriate requirements or sanctions on any VEPCO System Unit when emissions from the plant at which such unit is located result in violation of, or interfere with the attainment and maintenance of, any ambient air quality standard, or the plant fails to operate in conformance with any applicable control strategy, including any emissions standards or emissions limitations.

122. Nothing in this Section shall prevent the Commonwealth from issuing to any VEPCO System Unit a permit under either Article 5 (9 VAC 5-80-800 et seq.) or Article 6 (9 VAC 5-80-1100 et seq.) for the purpose of preserving the terms and conditions of this Decree as applicable federal requirements upon the expiration of the Decree.

XV. REOPENING OF VIRGINIAS' CLAIMS RESOLVED BY SECTION XIV

123. Bases for Pursuing Resolved Claims Across VEPCO System. If VEPCO:

(A) Violates Paragraph 59(A) or (B) (VEPCO System-Wide, Interim Control of NOx Emissions, 2004 through 2007); or

(B) Violates Paragraph 60 (VEPCO System-Wide NOx Tonnage Limits 2003 and thereafter: Declining, System-Wide Tonnage Caps); or

(C) Violates Paragraph 61 (VEPCO System-Wide Average NOx Emission Rate) in any calendar year (or ozone season, as applicable); or

(D) Fails by more than ninety days to complete installation of and commence timely year-round operation of any SCR or FGD required by Paragraphs 56 or 64 or Sections VIII or IX; or

(E) Fails to limit VEPCO System SO2 emissions to 203,693 tons or less in each calendar year starting with 2005 and thereafter;

then the Commonwealth of Virginia may pursue any claims at any VEPCO System Unit located in the Commonwealth otherwise resolved under Section XIV, where the modification(s) on which such claim is based was commenced, under way, or completed within five years preceding the violation or failure specified above, unless such modification was undertaken at an Improved Unit and commenced prior to the date of lodging of this Consent Decree.

124. Other Units. The resolution of claims of the Commonwealth of Virginia in Section XIV shall not apply to claims arising from modifications at Other Units located in the Commonwealth commenced less than five years prior to the occurrence of one or more of the following:

(A) One or more modifications at such Other Unit commenced after lodging of this Decree, individually or collectively, increase the maximum hourly emission rate for such Unit for the relevant pollutant (NOx or SO2) as measured by 40 C.F.R. Section 60.14(b) and (h); or

(B) The aggregate of all Capital Expenditures made at such Other Unit is in excess of $125/KW on the Unit's Boiler Island (based on the Maximum Dependable Capacity numbers in the North American Electric Reliability Council's Generating Availability Database for the year 2002) during any of the following five-year periods: January 1, 2001, through December 31, 2005; January 1, 2006, through December 31, 2010; January 1, 2011, through December 31, 2015. (Capital Expenditures shall be measured in calendar year 2000 constant dollars, as adjusted by the McGraw-Hill Engineering News-Record Construction Cost Index); or

(C) Modification(s) commenced after lodging of this Decree resulting in emissions increase(s) of the relevant pollutant that actually occurred from any such Other Unit, where such increase(s):

(1) present by themselves or in combination with other sources "an imminent and substantial endangerment" within the meaning of Section 303 of the Act, 42 U.S.C. Section 7603; or

(2) cause or contribute to violation of a National Ambient Air Quality Standard in any Air Quality Control Area that is in attainment with that NAAQS; or

(3) cause or contribute to violation of a PSD increment; or

(4) cause or contribute to any adverse impact on any formally recognized air quality and related values in any Class I area.

Solely for purposes of this Subparagraph (C ), (1) determination of whether there is an emissions increase that actually occurred resulting from modification(s) at the Unit must take into account any emissions changes relevant to the modeling domain that have occurred or will occur under this Decree at other VEPCO System Units; and (2) no such increase from a Unit will be deemed to have occurred if annual emissions of the relevant pollutant from all VEPCO System Units at the plant at which such Unit is located (and treating Mount Storm and North Branch as a single plant for this purpose) do not exceed such plant's emissions of that pollutant after lodging of this Consent Decree, as specified in Paragraph 112. Also, introduction of any new or changed National Ambient Air Quality Standard shall not, standing alone, provide the showing needed under this Subparagraph (C) (1)-(4) to pursue any claim resolved under Section XIV.

125. Improved Units. The resolution of claims provided by Section XIV shall not apply to a modification (or collection of modifications), if commenced after lodging of this Decree, at an Improved Unit located in the Commonwealth that individually (or collectively) increase the maximum hourly emission rate of that Unit for NO_x or SO₂ (as measured by 40 C.F.R. Section 60.14 (b) and (h)) by more than ten percent (10%) of the maximum hourly emission rate for that Unit.

XVI. RESOLUTION OF CIVIL CLAIMS OF THE STATE OF WEST VIRGINIA

126. Claims Based on Modifications Occurring Before the Lodging of Decree. Subject to the specific limitations in this Section, entry of this Decree shall resolve all civil claims of the State of West Virginia that arose under applicable federal statutes and regulations (Section 7410 (a)(2)(C), Parts C or D of Subchapter I of the Clean Air Act or 40 CFR Section 60.14) or applicable state regulations (45CSR13, 45CSR14 and 45CSR19, as well as the provisions of 45CSR16 that are equivalent to 40 CFR Section 60.14(a)) and, as to the state regulations, all applicable predecessor regulations, from any modification (physical change or change in the method of operation, including but not limited to construction of any air pollution control project at any VEPCO System Unit). This Paragraph shall apply to any modification at any VEPCO System Unit located in West Virginia commenced prior to the date of lodging of this Decree.

127. Claims Based on Modifications after the Lodging of Decree. Subject to the specific limitations in this Section, entry of this Decree shall also resolve all civil claims of the State of West Virginia arising under applicable federal statutes (Section 7410 (a)(2)(C) and Parts C or D of Subchapter I of the Clean Air Act) or applicable state regulations (45CSR13, 45CSR14 and 45CSR19 and any successor regulations from any modification (physical change or change in the method of operation, including but not limited to construction of any air pollution control project at any VEPCO system Unit. This Paragraph shall apply to any modification at any VEPCO System Unit located in West Virginia commenced on or after the date of lodging of this Decree that is completed before December 31, 2015, or is among those that this Consent Decree expressly directs VEPCO to undertake.

128. Reopener. The resolution of the civil claims of the State of West Virginia provided by this Section is subject to the provisions of Section XVII.

129. General. Each term used in Paragraph 127 that is also a term used under the Clean Air Act shall mean what such term means under the Act as it existed on the date of lodging of this Decree.

130. West Virginia's Authority Regarding NAAQS Exceedances. Nothing in this Decree shall be construed to affect West Virginia's authority under applicable federal statutes and applicable state statutes or regulations to impose appropriate requirements or sanctions on any VEPCO System Unit when emissions from the plant at which such unit is located result in violation of, or interfere with the attainment and maintenance of, any ambient air quality standard, or the plant fails to operate in conformance with any applicable control strategy, including any emissions standards or emissions limitations.

131. Nothing in this Section shall prevent West Virginia from issuing to any VEPCO System Unit a permit under either 45CSR13 or 45CSR14) for the purpose of preserving the terms and conditions of this Decree as applicable federal requirements upon the expiration of the Decree.

XVII. REOPENING OF WEST VIRGINIA'S CLAIMS RESOLVED BY SECTION XVI.

132. Bases for Pursuing Resolved Claims Across VEPCO System. If VEPCO:

(A) Violates Paragraph 59(A) or (B) (VEPCO System-Wide, Interim Control of NOx Emissions, 2004 through 2007); or

(B) Violates Paragraph 60 (VEPCO System-Wide NOx Tonnage Limits 2003 and thereafter: Declining, System-Wide Tonnage Caps); or

(C) Violates Paragraph 61 (VEPCO System-Wide Average NOx Emission Rate) in any calendar year (or ozone season, as applicable); or

(D) Fails by more than ninety days to complete installation of and commence timely year-round operation of any SCR or FGD required by Paragraphs 56 or 64 or Sections VIII or IX; or

(E) Fails to limit VEPCO System SO2 emissions to 203,693 tons or less in each calendar year starting with 2005 and thereafter;

then the State of West Virginia may pursue any claims at any VEPCO System Unit located in the state otherwise resolved under Section AA, where the modification(s) on which such claim is based was commenced, under way, or completed within five years preceding the violation or failure specified above, unless such modification was undertaken at an Improved Unit and completed prior to the date of lodging of this Consent Decree.

133. Other Units. The resolution of claims of the State of West Virginia in Section AA shall not apply to claims arising from modifications at Other Units located in West Virginia commenced less than five years prior to the occurrence of one or more of the following:

(A) One or more modifications at such Other Unit, individually or collectively, increase the maximum hourly emission rate for such Unit for the relevant pollutant (NOx or SO2) as measured by 40 C.F.R. Section 60.14(b) and (h); or

(B) The aggregate of all Capital Expenditures made at such Other Unit is in excess of $125/KW on the Unit's Boiler Island (based on the Maximum Dependable Capacity numbers in the North American Electric Reliability Council's Generating Availability Database for the year 2002) during any of the following five-year periods: January 1, 2001, through December 31, 2005; January 1, 2006, through December 31, 2010; January 1, 2011, through December 31, 2015. (Capital Expenditures shall be measured in calendar year 2000 constant dollars, as adjusted by the McGraw-Hill Engineering News-Record Construction Cost Index); or

(C) Modification(s) resulting in emissions increase(s) of the relevant pollutant that actually occurred from any such Other Unit, where such increase(s):

(1) present by themselves or in combination with other sources "an imminent and substantial endangerment" within the meaning of Section 303 of the Act, 42 U.S.C. Section 7603; or

(2) cause or contribute to violation of a National Ambient Air Quality Standard in any Air Quality Control Area that is in attainment with that NAAQS; or

(3) cause or contribute to violation of a PSD increment; or

(4) cause or contribute to any adverse impact on any formally recognized air quality and related values in any Class I area.

Solely for purposes of this Subparagraph (C ), (i) determination of whether there is an emissions increase that actually occurred resulting from modification(s) at the Unit must take into account any emissions changes relevant to the modeling domain that have occurred or will occur under this Decree at other VEPCO System Units; and (ii) no such increase from a Unit will be deemed to have occurred if annual emissions of the relevant pollutant from all VEPCO System Units at the plant at which such Unit is located (and treating Mount Storm and North Branch as a single plant for this purpose) do not exceed such plant's emissions of that pollutant, as specified in Paragraph 112. Also, introduction of any new or changed National Ambient Air Quality Standard shall not, standing alone, provide the showing needed under this Subparagraph (C) (1)-(4) to pursue any claim resolved under Section XVI.

134. Improved Units. The resolution of claims provided by Section XVI shall not apply to a modification (or collection of modifications), if commenced after lodging of this Decree, at an Improved Unit located in West Virginia that individually (or collectively) increase the maximum hourly emission rate of that Unit for NO_x or SO₂ (as measured by 40 C.F.R. Section 60.14 (b) and (h)) by more than ten percent (10%) of the maximum hourly emission rate for that Unit.

XVIII. OTHER PROVISIONS ON ALLOWANCES AND CREDITS

135. NO_x Credits. For any and all actions taken by VEPCO to conform to the requirements of this Decree, VEPCO shall not use or sell any resulting NO_x emission allowances or credits in any emission trading or marketing program of any kind; provided, however that:

(A) NO_x emission allowances or credits allocated to the VEPCO System by the Administrator of EPA under the Act, or by any State under its SIP in response to the EPA NO_x SIP Call, or the EPA Section 126 Rulemaking, or any other similar emissions trading or marketing program of any kind, may be used by VEPCO and its parent company (Dominion Resources) or its subsidiaries or affiliates to meet their own federal and/or state Clean Air Act regulatory requirements for any air emissions source owned or operated, in whole or in part, by VEPCO or Dominion Resources, Inc. or its subsidiaries or affiliates and;

(B) VEPCO may trade in any federal or state program any NO_x emissions allowances which are generated from VEPCO's operating its SCRs, or equivalent control technology, at Chesterfield Units 4, 5, and 6; or Chesapeake Units 3 and 4; or any VEPCO System Unit on which SCR is installed under Section IX (Installing Additional Units on VEPCO System Units), either:

(1) Earlier than required by this Decree or other applicable law; or

(2) At time periods of the year not required by this Consent Decree or by applicable law; or

(3) At a 30-Day Rolling Average Emission Rate that is more stringent than required by this Decree.

(C) VEPCO may trade in any federal or state program NO_x emissions allowances which are generated from VEPCO's operating its SCRs, or equivalent control technology, at Mt. Storm Units 1, 2, and 3 as follows:

(1) 100% of NOx allowances generated earlier than required by this Decree or other applicable law; or

(2) 100% of NOx allowances generated at time periods of the year not required by this Consent Decree or by applicable law; or (3) 50% of NOx allowances generated by achieving a 30-Day Rolling Average Emission Rate more stringent than required by this Consent Decree. The remaining 50% of the NOx allowances generated may be used in accordance with Subparagraph A or be retired.

136. Netting Limits. Nothing in this Decree shall prevent VEPCO from claiming creditable contemporaneous emissions decreases from emission reductions effected by VEPCO prior to the June 30, 2001. For emission control actions taken by VEPCO to conform with the terms of this Consent Decree, including, but not limited to, improvements to ESPs and FGDs, installation of FGDs, installation of SCRs, and the fuel conversion of Possum Point Units 3 and 4, any emission reductions generated up to the level necessary to comply with the provisions of this Decree (and excluding simple control equipment operating requirements) shall not be considered as a creditable contemporaneous emission decrease for the purpose of obtaining a netting credit under the Act's New Source Review program; provided, however, that nothing in this Decree shall be construed to prohibit VEPCO's seeking such treatment for decreases in emissions resulting from VEPCO's ceasing combustion of coal at Possum Point Unit 3 or Possum Point Unit 4, if:

(A) Such decreases are used in VEPCO's demonstrating whether the conversion of Possum Point Units 3 and 4 (plus the installation of up to two new units 540 MW (nominal) each, combined cycle electric generating units at Possum Point) would result in a net significant emissions increase; and

(B) VEPCO either (i) installs and continuously operates LAER on Possum Point Units 3 or 4 or (ii) demonstrates that the use of natural gas will result in a net emissions decrease; and

(C) VEPCO also complies with the NOx emissions cap and other requirements in Paragraph 96 for Possum Point Units 3 and 4 under this Decree and also installs SCR controls for NO_x on the new combined cycle unit(s).

XIX. PERIODIC REPORTING

137. Compliance Report. After entry of this Decree, VEPCO shall submit to Plaintiffs a periodic report, in compliance with Appendix B, within sixty (60) days after the end of each half of the calendar year (January through June and July through December).

138. Deviations Report. In addition to the reports required by the previous paragraph, if VEPCO violates or deviates from any provision of this Consent Decree, VEPCO shall submit to Plaintiffs a report on the violation or deviation within ten (10) business days after VEPCO knew or should have known of the event. In the report, VEPCO shall explain the cause or causes of the violation or deviation and any measures taken or to be taken by VEPCO to cure the reported violation or deviation or to prevent such violation or deviations in the future. If at any time, the provisions of the Decree are included in Title V Permits, consistent with the requirements for such inclusion in the Decree, then the deviation reports required under applicable Title V regulations shall be deemed to satisfy all the requirements of this Paragraph.

139. VEPCO's reports (Periodic and Deviations) shall be signed by VEPCO's Vice President of Fossil and Hydro, or, in his or her absence, VEPCO's Vice President of Technical Services, or higher ranking official, and shall contain the following certification:

I certify under penalty of law that this information was prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my directions and my inquiry of the person(s) who manage the system, or the person(s) directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. I understand that there are significant penalties for making misrepresentations to or misleading the United States.

140. If any allowances are surrendered to any third party pursuant to Section VI the third party's certification shall be signed by a managing officer of the third party's and shall contain the following language:

I certify under penalty of law that _____________ [name of third party] will not sell, trade, or otherwise exchange any of the allowances and will not use any of the allowances to meet any obligation imposed by any environmental law. I understand that there are significant penalties for making misrepresentations to or misleading the United States.

XX. CIVIL PENALTY

141. Within thirty (30) calendar days of entry of this Consent Decree, VEPCO shall pay to the United States a civil penalty of $5.3 million. The civil penalty shall be paid by Electronic Funds Transfer ("EFT") to the United States Department of Justice, in accordance with current EFT procedures, referencing the USAO File Number 2003V00487 and DOJ Case Number 90-5-2-1-07122 and the civil action case name and case number of this action. The costs of EFT shall be VEPCO's responsibility. Payment shall be made in accordance with instructions provided by the Financial Litigation Unit of the U.S. Attorney's Office for the Eastern District of Virginia. Any funds received after 11:00 a.m. (EST) shall be credited on the next business day. VEPCO shall provide notice of payment, referencing the USAO File Number, DOJ Case Number 90-5-2-1-07122, and the civil action case name and case number, to the Department of Justice and t o EPA, as provided in Section XXIX, Paragraph 187 ("Notice"). Failure to timely pay the civil penalty shall subject VEPCO to interest accruing from the date payment is due until the date payment is made at the rate prescribed by 28 U.S.C.
Section 1961, and shall render VEPCO liable for all charges, costs, fees, and penalties established by law for the benefit of a creditor or of the United States in securing payment.

XXI. MITIGATION PROJECTS

142. General. VEPCO shall submit for review and approval plans for the completion of the Mitigation Projects described in this Section, complying with the schedules and other terms of this Consent Decree and plans for such Projects approved under this Decree. In performing these Projects, VEPCO shall spend no less than $13.9 million Project Dollars. VEPCO shall make available the full amount of the Project Dollars required by this Paragraph within one year of entry of this Decree. VEPCO shall maintain for review by the Plaintiffs, upon request, all documents identifying Project Dollars spent by VEPCO. All plans and reports prepared by VEPCO or by other persons pursuant to the requirements of this Section of the Consent Decree shall be publicly available from VEPCO, without charge. No Project Dollars may be made available or expended to undertake an obligation already required by law.

143. Good Faith. VEPCO shall use good faith efforts to secure as much benefit as possible for the Project Dollars expended, consistent with the applicable requirements and limits of this Decree.

144. Other Project Requirements. In addition to the requirements imposed for each Project specified in this Decree, including Appendix C and the approved plans, the following requirements shall apply. If VEPCO elects (where such election is allowed) to undertake a Project by contributing funds to another person or instrumentality to carry out the Project, that person or instrumentality must, in writing: (A) identify its legal authority for accepting such funding, and (B) identify its legal authority to conduct the Project for which VEPCO contributes the funds. Regardless of whether VEPCO elects (where such election is allowed) to undertake the Project itself or to do so by contributing funds to another person or instrumentality that will carry out the Project, VEPCO acknowledges that it shall receive credit for expenditure of such funds as Project Dollars only in accordance with the approved plans. Provided however, that when VEPCO elects to undertake a Project by providing funds to a State or any instrumentality thereof, VEPCO shall receive credit for any timely expenditure of funds upon transfer of such funds to such State or instrumentality thereof, as long as the VEPCO provides payment in accordance with Appendix C and the approved plan. VEPCO shall certify, as part of the proposed plan submitted to the Plaintiffs for any contemplated Project, that no person is required by any law, other than this Consent Decree, to perform the Project described in the proposed plan. Within sixty (60) days following the completion of each approved Project, VEPCO shall submit to the Plaintiffs a report that documents the date that all aspects of the project were implemented, VEPCO's results in completing the project, including the emission reductions or other environmental or health benefits achieved, and the Project Dollars expended by VEPCO in implementing the Project. Based on consideration of these reports and the approved plans, and any other available, relevant information, the United States (after consultati on with the other Plaintiffs) will advise VEPCO whether the Project has met the requirements of the Decree. VEPCO shall submit the required plans for, and complete, each Project, as approved by the United States, and by any other Plaintiff within whose territory a Project would be implemented, all as specified further in Appendix C to this Decree.

XXII. STIPULATED PENALTIES & ALLOWANCE OR CREDIT SURRENDERS

145. Within thirty (30) days after written demand from the United States, and subject to the provisions of Sections XXVI ("Force Majeure") and XXVII ("Dispute Resolution"), VEPCO shall pay the following stipulated penalties to the United States (and surrender the specified number of emission allowances or credits) for each failure by VEPCO to comply with the terms of this Consent Decree, as follows.

146. For each violation of each limit, rate or removal efficiency that is measured on a 30-day Rolling Average or shorter averaging period imposed on NO_x , SO₂, and PM under Sections IV, V, VII, VIII ("Possum Point"), and IX ("Installing Additional Controls on VEPCO System Units"):

1. less than 5% in excess of the limit: $2,500 per day per violation;
2. equal to or greater than 5% in excess of the limit: $5,000 per day per violation;
3. equal to or greater than 10% in excess of the limit: $10,000 per day per violation.
4. For failure to meet any VEPCO System-Wide emissions requirement (Paragraph 59(A) and (B) "VEPCO System: Interim Control of NOX Emissions: 2004 through 2007; Paragraph 60"VEPCO System NOX Limits 2003 and thereafter: Declining , System-Wide Tonnage Caps; and Paragraph 61 VEPCO System -Wide, Annual Average NOX Emission Rate): $5,000 per ton for the first 100 tons resulting from the violation, and $10,000 per ton for each additional ton resulting from the violation.

147. Other Specific Failures. For failure to:

(A) install timely and commence operation timely of SCR on each Unit (each SCR installation) specified in Section IV, Paragraph 56 ("Unit-Specific SCR Installations and Annual Performance Requirements"): (i) $10,000 per day, per violation, for the first 30 days; and (ii) $27,500 per day, per violation, thereafter.

(B) complete any FGD improvements or installation needed to meet emission limits imposed under Section V, Paragraph 64 ("Construction, Upgrading, and Removal Efficiencies Required or on FGDs Serving Clover Units 1 and 2, Mount Storm Unites 1, 2, and 3, and Chesterfield Units 5 and 6"): (i) $ 10,000 per day, per violation, for the first 30 days; and (ii) $20,000 per day, per violation, thereafter.

(C) surrender timely the annually-required 45,000 SO₂ Allowances surrender under Section VI: $27,500 per day, per violation plus the surrender 100 additional SO₂ Allowances per day per violation.

(D) timely transfer the annually-required surrender of 45,000 SO₂ Allowances by VEPCO to any third party under Section VI: $27,500 per day, per violation plus the surrender 100 additional SO₂ Allowances per day per violation.

(E) comply with any requirement in this Consent Decree regarding the use of any SO₂ or NO_x allowances or credits: surrender three times the allowances or credits handled in violation of the requirement.

(F) complete timely the proper installation of all equipment called for under Section VII (PM Emission Reductions and Controls) or under any plan or submission approved by EPA under Section VII: (i) $ 10,000 per day, per violation, for the first 30 days; and (ii) $20,000 per day, per violation, thereafter.

(G) conduct a required stack test of PM emissions on each VEPCO System Unit where such test is required under Section VII: $1,000 per day, per violation.

(H) Submit timely and complete reports called for under Section XIX ("Periodic Reporting"): $1,000 per day, per violation.

(I) Complete any funding for any of the Projects described in Section XXI (Mitigation Projects): $1,000 per day, per violation for the first 30 days; and $5,000 per day, per violation thereafter.

148. Violations of any limit based on a 30-Day Rolling Average constitutes thirty (30) days of violation but where such a violation (for the same pollutant and from the same Unit or source) recurs within periods less than thirty (30) days, VEPCO shall not be obligated to pay a daily stipulated penalty, for any day of the recurrence for which a stipulated penalty has already been paid.

XXIV. ACCESS, AND INFORMATION COLLECTION AND RETENTION

149. Access, Inspection, Investigation. Any authorized representative of EPA, including independent contractors, upon presentation of credentials, shall have a right of entry upon the premises of any facility in the VEPCO System at any reasonable time and for any reasonable purpose regarding monitoring compliance with the provisions of this Consent Decree, including inspecting plant equipment and inspecting and copying all records maintained by VEPCO required by this Consent Decree. VEPCO shall retain such records for a period of fifteen (15) years from the date of entry of this Consent Decree. Nothing in this Consent Decree shall limit any information-gathering or inspection authority of EPA under the Act, including but not limited to Section 114 of the Act, 42 U.S.C. Section 7414.

XXV. COORDINATION OF ENFORCEMENT & DISPUTE RESOLUTION

150. United States - Enforcement and Dispute Resolution. The United States may enforce any and all requirements of this Decree and may invoke dispute resolution provisions of this Decree as to any requirement of this Decree to which dispute resolution applies and also may participate in adjudication of any claim of Force Majeure made by VEPCO or any other Party.

151. VEPCO - Dispute Resolution. VEPCO may invoke the dispute resolution provisions of this Decree over any requirement of this Decree to which dispute resolution applies.

152. States - Enforcement. Consistent with Section XXV, The State of New York, New Jersey, or Connecticut, or any combination of them, may enforce only the following requirements of this Decree:

(A) those requirements imposed directly on a Unit at Mount Storm, Chesterfield, and Possum Point;

(B) any or all of the following VEPCO System-Wide requirements: Section IV Paragraph 59 ("Interim NO_x Emissions for VEPCO System"), Paragraph 60 ("VEPCO System NO_x Declining Tonnage Caps") and Paragraph 61 ("NO_x System-Wide Average Emission Rate"] and Section VI, Paragraph 71 (Annual Surrender of SO₂ Allowances); and

(C) those requirements involving timely and proper performance of Decree-mandated mitigation projects (Section XXI and Appendix C).

153. The Commonwealth of Virginia and the State of West Virginia may enforce all of the requirements of this Decree applicable to VEPCO units within their respective jurisdictions, including the system-wide cap.

154. States - Dispute Resolution. The States of New York, New Jersey, Connecticut, Virginia, or West Virginia, or any combination of them, may invoke dispute resolution only over those Decree requirements that such State could enforce under this Decree and may participate as a plaintiff in any matter in which VEPCO asserts Force Majeure under this Decree only if the matter concerns a requirement which such State could have enforced under the terms of this Decree. Notwithstanding the preceding sentence, the States of New York, New Jersey, Connecticut, Virginia, or West Virginia, or any combination of them, may participate as a plaintiff in any matter in which VEPCO asserts force majeure under this Decree, to the extent that resolution of the legal issue(s) at stake in that matter would affect the ability of New York, New Jersey, Connecticut, Virginia, or West Virginia to enforce any of the requirements specified in Paragraphs 152 and 153_of this Section.

155. Consultation Among Plaintiffs. Absent exigent circumstances, the United States, New York, New Jersey, Connecticut shall consult prior to enforcing a requirement under this Decree or prior to invoking Dispute Resolution (Section ) for any issue, which the given State could enforce under this Decree. Absent exigent circumstances, the United States, Virginia, and West Virginia shall consult prior to enforcing a requirement under this Decree or prior to invoking Dispute Resolution (Section XXVII) for any issue which the given State could enforce under this Decree. If such consultation reveals that, for any reason, the United States does not intend to participate, in the first instance, in either the Decree enforcement or invocation of Dispute Resolution contemplated by New York, New Jersey, or Connecticut, Virginia, or West Virginia then the consultation required by this Section is not satisfied until after "Senior Management Level Officials" of United States consult with the "Senior Management Le vel Officials" of each Plaintiff intending to enforce a requirement under the Decree or to invoke dispute resolution under it. The United States shall undertake such consultation and shall complete it within twenty-eight (28) days after the consultation with the States and the United States demonstrates that the United States does not intend to participate in the activity contemplated by one or more of the States. Only for purposes of the consultation requirement of this Section, "Senior Management Level Official" means:

(A) For the United States: Director of the Office of Regulatory Enforcement, U.S. EPA Office of Enforcement and Compliance Assurance, and Chief of the Environmental Enforcement Section, U.S. DOJ Environment & Natural Resources Division;

(B) For New York: Chief of the Environmental Protection Bureau, Office of the Attorney General of the State of New York;

(C) For New Jersey: Assistant Attorney General in Charge of Environmental Protection, Office of the Attorney General of the State of New Jersey;

(D) For Connecticut: Director of the Environmental Department, Office of the Attorney General for the State of Connecticut;

(E) For Virginia: Director of the Environmental Unit, Special Prosecutions Section, Public Safety and Law Enforcement Division, Office of the Attorney General of the Commonwealth of Virginia; and

(F) For West Virginia: Director of the Division of Air Quality, West Virginia Department of Environmental Protection

156. Confirmation of Consultation. Contemporaneous with any filing to enforce the Decree or to invoke Dispute Resolution (Section XXVII), the moving Plaintiff shall serve on VEPCO a written statement noting that the consultation required by this Section has been completed, unless Plaintiff is relying on the "exigent circumstances" exception of this Section. If a Plaintiff invokes the "exigent circumstances" exception in lieu of completing this consultation process, that Plaintiff must then serve on VEPCO an explanation of the need for acting in advance of completing such consultation. "Exigent" is intended to have its normal meaning when used in this Section of the Decree, and reliance by a Plaintiff on this exception is subject to review by the Court.

XXVI. FORCE MAJEURE

157. General. If any event occurs which causes or may cause a delay in complying with any provision of this Consent Decree or causes VEPCO to be in violation of any provision of this Decree, VEPCO shall notify the Plaintiffs in writing as soon as practicable, but in no event later than ten (10) business days following the date VEPCO first knew, or within ten (10) business days following the date VEPCO should have known by the exercise of due diligence, that the event caused or may cause such delay or violation, whichever is earlier. In this notice, VEPCO shall reference this Paragraph of this Consent Decree and describe the anticipated length of time the delay or violation may persist, the cause or causes of the delay or violation, the measures taken or to be taken by VEPCO to prevent or minimize the delay or violation, and the schedule by which those measures will be implemented. VEPCO shall adopt all reasonable measures to avoid or minimize such delays and prevent such violations.

158. Failure of Notice. Failure by VEPCO to comply with the notice requirements of this Section shall render this Section voidable by the Plaintiffs authorized under Sections XXV (Coordination of Enforcement and Dispute Resolution) to enforce a Consent Decree requirement against which VEPCO could interpose the force majeure assertion in question. If voided, the provisions of this Section shall have no effect as to the particular event involved.

159. Plaintiffs' Response. The Plaintiffs authorized under Sections XXV (Coordination of Enforcement and Dispute Resolution) to enforce a Consent Decree requirement against which VEPCO could interpose the force majeure assertion in question shall notify VEPCO, in writing, regarding VEPCO's claim of a delay in performance or violation within fifteen (15) business days after completion of procedures specified in Section XXV ("Enforcement Coordination"). If the Plaintiffs agree that the delay in performance or the violation has been or will be caused by circumstances beyond the control of VEPCO, including any entity controlled by VEPCO, and that VEPCO could not have prevented the delay through the exercise of due diligence, the parties shall stipulate to such relief as appropriate, which shall usually be an extension of the required deadline(s) for every requirement affected by the delay for a period equivalent to the delay actually caused by such circumstances. Such stipulation shall be filed as a modification to this Consent Decree in order to be effective. VEPCO shall not be liable for stipulated penalties for the period of any such delay.

160. Disagreement. If the Plaintiffs authorized under Sections XXV (Coordination of Enforcement and Dispute Resolution) to enforce a Consent Decree requirement against which VEPCO could interpose the force majeure assertion in question, do not accept VEPCO's claim that a delay or violation has been or will be caused by a Force Majeure event, or do not accept VEPCO's proposed remedy, to avoid the imposition of stipulated penalties VEPCO must submit the matter to this Court for resolution by filing a petition for determination. Once VEPCO has submitted the matter, the United States, and other Plaintiffs as provided in Paragraph 159, shall have fifteen (15) business days to file a response(s). If VEPCO submits the matter to this Court for resolution, and the Court determines that the delay in performance or violation has been or will be caused by circumstances beyond the control of VEPCO, including any entity controlled by VEPCO, and that VEPCO could not have prevented the delay or violation by the exercise of due diligence, VEPCO shall be excused as to that event(s) and delay (including stipulated penalties otherwise applicable), but only for the period of time equivalent to the delay caused by such circumstances.

161. Burden of Proof. VEPCO shall bear the burden of proving that any delay in performance or violation of any requirement of this Consent Decree was caused by or will be caused by circumstances beyond its control, including any entity controlled by it, and that VEPCO could not have prevented the delay by the exercise of due diligence. VEPCO shall also bear the burden of proving the duration and extent of any delay(s) or violation(s) attributable to such circumstances. An extension of one compliance date based on a particular event may, but will not necessarily, result in an extension of a subsequent compliance date.

162. Events Excluded. Unanticipated or increased costs or expenses associated with the performance of VEPCO's obligations under this Consent Decree shall not constitute circumstances beyond the control of VEPCO or serve as a basis for an extension of time under this Section. However, failure of a permitting authority to issue a necessary permit in a timely fashion may constitute a Force Majeure event where the failure of the permitting authority to act is beyond the control of VEPCO, and VEPCO has taken all steps available to it to obtain the necessary permit, including, but not limited to, submitting a complete permit application, responding to requests for additional information by the permitting authority in a timely fashion, accepting lawful permit terms and conditions, and prosecuting appeals of any allegedly unlawful terms and conditions imposed by the permitting authority in an expeditious fashion.

163. Potential Force Majeure Events. The parties agree that, depending upon the circumstances related to an event and VEPCO's response to such circumstances, the kinds of events listed below could qualify as Force Majeure events: construction, labor, or equipment delays; acts of God; Malfunction for PM as malfunction is defined in 40 C.F.R. 60.2; and orders by governmental officials, acting under and authorized by applicable law, that direct VEPCO to supply electricity in response to a legally declared, system-wide (or state-wide) emergency.

164 Prohibited Inferences. Notwithstanding any other provision of this Consent Decree, this Court shall not draw any inferences nor establish any presumptions adverse to any party as a result of VEPCO delivering a notice pursuant to this Section or the parties' inability to reach agreement on a dispute under this Part.

165. Extended Schedule. As part of the resolution of any matter submitted to this Court under this Section, the Parties by agreement with approval from this Court, or this Court by order, may, as allowed by law, extend the schedule for completion of work under this Consent Decree to account for the delay in the work that occurred as a result of any delay or violation. VEPCO shall be liable for stipulated penalties for its failure thereafter to complete the work in accordance with the extended schedule.

XXVII. DISPUTE RESOLUTION

166. Scope of Disputes Covered and Eligibility of Parties to Participate. The dispute resolution procedure provided by this Section shall be available to resolve all disputes arising under this Consent Decree, except as provided in Section XXVI ("Force Majeure") or in this Section, provided that the Party making such application has made a good faith attempt to resolve the matter with the other Parties. Invocation and participation of this Section also shall be done in compliance with Section XXV ("Coordination of Enforcement and Dispute Resolution").

167. Invocation of Procedure. The dispute resolution procedure required herein shall be invoked by one Party to this Consent Decree giving written notice to another advising of a dispute pursuant to this Section. The notice shall describe the nature of the dispute and shall state the noticing party's position with regard to such dispute. The Party receiving such a notice shall acknowledge receipt of the notice, and the parties shall expeditiously schedule a meeting to discuss the dispute informally not later than fourteen (14) days following receipt of such notice.

168. Informal Phase. Disputes submitted to dispute resolution under this Section shall, in the first instance, be the subject of informal negotiations among the parties. Such period of informal negotiations shall not extend beyond thirty (30) calendar days from the date of the first meeting among the Parties' representatives unless they agree to shorten or extend this period.

169. Formal Phase. If the Parties are unable to reach agreement during the informal negotiation period, the Plaintiffs, shall provide VEPCO with a written summary of their position regarding the dispute. The written position provided by the Plaintiffs shall be considered binding unless, within thirty (30) calendar days thereafter, VEPCO files with this Court a petition that describes the nature of the dispute and seeks resolution. The Plaintiffs may respond to the petition within forty-five (45) calendar days of filing. Where the nature of the dispute is such that a more timely resolution of the issue is required, the time periods set out in this Section may be shortened upon successful motion of one of the parties to the dispute.

170. Prohibited Inference. This Court shall not draw any inferences nor establish any presumptions adverse to either party as a result of invocation of this Section or the parties' inability to reach agreement.

171. Alteration of Schedule. As part of the resolution of any dispute under this Section, in appropriate circumstances the parties may agree, or this Court may order if warranted by law, an extension or modification of the schedule for completion of work under this Consent Decree to account for the delay that occurred as a result of dispute resolution. VEPCO shall be liable for stipulated penalties for its failure thereafter to complete the work in accordance with the extended or modified schedule.

172. Applicable Standard of Law. The Court shall decide all disputes pursuant to applicable principles of law for resolving such disputes; provided, however, that the parties reserve their rights to argue for what the applicable standard of law should be for resolving any particular dispute. Notwithstanding the preceding sentence of this Paragraph, as to disputes involving the submittal for review and approval under Section VII, the Court shall sustain the position of the United States as to disputes involving PM CEMs, any Pollution Control Upgrade Analysis, and optimization measures for PM that should be undertaken - unless VEPCO demonstrates that the position of the United States is arbitrary or capricious.

XXVIII. SALES OR TRANSFERS OF OWNERSHIP INTERESTS

173. Joint and Several Liability By Transfer of Certain VEPCO Property. If VEPCO proposes to sell or transfer any of its real property or operations subject to this Consent Decree, VEPCO shall advise the purchaser or transferee in writing of the existence of this Consent Decree prior to such sale or transfer, and shall send a copy of such written notification to the Plaintiffs pursuant to Section XXIX, Paragraph 187 ("Notices") at least sixty (60) days before such proposed sale or transfer. Before closing such purchase or transfer, a modification of this Consent Decree shall make the purchaser or transferee a party defendant to this Decree and jointly and severally liable with VEPCO for all the requirements of this Decree that may be applicable to the transferred or purchased property or operations, including joint and several liability with VEPCO for all Unit-specific requirements and all VEPCO System-Wide requirements, namely: VEPCO System-Wide Annual Average Emission Rate for NO_{x (Section IV), SO2 Allowance surrenders (Section VI), and VEPCO System NOx annual tonnage caps (Section IV) .}

174. Option for Alternative Request on System-Wide obligations. VEPCO may propose and the United States may agree to restrict the scope of joint and several liability of any purchaser or transferee for any VEPCO System-Wide obligations to the extent such obligations may be adequately separated in an enforceable manner using the methods provided by or approved under Section X ("Permits").

175. Option for Alternative Request on Particular VEPCO System Units. VEPCO also may propose, and the United States may agree to execute, a modification that transfers responsibility for completing Decree-required capital improvements from VEPCO to the purchaser of property at which the capital improvement is required.

176. Standard for Reviewing a VEPCO Request. Liability transfers sought by VEPCO under this Section of the Decree shall be granted by the United States (or by all the Plaintiffs, as applicable) if the relevant Plaintiffs agree that:

(A) The purchaser or transferee has appropriately contracted with VEPCO to assume the obligations and liabilities applicable to the Unit; and

(B) VEPCO and the purchaser or transferee have properly allocated any emission allowance, credit requirement, or other Decree-imposed obligation on the VEPCO System, which also implicates the Unit to be transferred.

In the case of transfers of VEPCO System Units at Chesterfield and/or Mount Storm, VEPCO's scope of liability for either VEPCO System-Wide requirements or for Decree-required capital improvement on Units at those plants shall not be transferred unless the States of New York, New Jersey, and Connecticut concur with the United States' determination to accept liability of only the purchaser or transferee, as opposed to joint and several liability between VEPCO and the purchaser.

177. No limit on contractual allocation of responsibility that does not affect rights of the Plaintiffs. This Section of the Decree shall not be construed to impede VEPCO and any purchaser or transferee of real property or operations subject to this Decree from contractually allocating as between themselves the burdens of compliance with this Decree, provided that both VEPCO and such purchaser or transferee shall remain jointly and severally liable to the Plaintiffs for those obligations of the Decree specified above, absent approval under this Section of a VEPCO request to allocate liability.

XXIX. GENERAL PROVISIONS

178. Effect of Settlement. This Consent Decree is not a permit; compliance with its terms does not guarantee compliance with all applicable Federal, State, or Local laws or regulations.

179. Criminal Liability. This Consent Decree does not apply to any claim(s) of alleged criminal liability, which are reserved, nor to any claims resolved and then reopened under the terms of this Decree.

180. Limitation on Procedural Bars to Other Claims. In any subsequent administrative or judicial action initiated by Plaintiffs for injunctive relief or civil penalties relating to the facilities covered by this Consent Decree, VEPCO shall not assert any defense or claim based upon principles of waiver, res judicata, collateral estoppel, issue preclusion, claim splitting, or other defense based upon any contention that the claims raised by the Plaintiffs in the subsequent proceeding were brought, or should have been brought, in the instant case; provided, however, that nothing in this Paragraph is intended to affect the validity of Sections XI through XVII (Resolution of Certain Civil Claims).

181. Other Laws. Except as specifically provided by this Consent Decree, nothing in this Consent Decree shall relieve VEPCO of its obligation to comply with all applicable Federal, State, and Local laws and regulations. Subject to Sections XI through XVII, nothing contained in this Consent Decree shall be construed to prevent or limit the Plaintiffs' rights to obtain penalties or injunctive relief under the Clean Air Act or other federal, state, or local statutes or regulations.

182. Third Parties. This Consent Decree does not limit, enlarge, or affect the rights of any party to this Consent Decree as against any third parties.

183 Costs. Each party to this action shall bear its own costs and attorneys' fees.

184 Public Documents. All information and documents submitted by VEPCO to the United States or the other Plaintiffs under this Consent Decree shall be subject to public inspection, unless subject to legal privileges or protection or identified and supported as business confidential, under applicable law. VEPCO may not seek such protection concerning submittals required by the Decree that concern mitigation projects (Section XXI).

185. Public Comment. The parties agree and acknowledge that final approval by the United States and entry of this Consent Decree is subject to the policy statement reproduced at Title 28 C.F.R. Section 50.7, which provides for notice of the lodging of this Consent Decree in the Federal Register, an opportunity for public comment, and the right of the United States to withdraw or withhold consent if the comments disclose facts or considerations which indicate that the Consent Decree is inappropriate, improper, or inadequate.

186. Notice. Unless otherwise provided herein, notifications to or communications with the Plaintiffs or VEPCO shall be deemed submitted on the date they are postmarked and sent either by overnight mail, return receipt requested, or by certified or registered mail, return receipt requested. Except as otherwise provided herein, when written notification to or communication with the Plaintiffs or VEPCO is required by the terms of this Consent Decree, it shall be addressed as follows:

For the United States of America:

Chief
Environmental Enforcement Section
U.S. Department of Justice
P.O. Box 7611, Ben Franklin Station
Washington, D.C. 20044-7611
DJ# 90-5-2-1-07122

- and -

Director, Air Enforcement Division
Office of Enforcement and Compliance Assurance
U.S. Environmental Protection Agency
Ariel Rios Building [2242A]
1200 Pennsylvania Avenue, N.W.
Washington, DC 20460

- and -

Regional Administrator
U.S. EPA Region III
1650 Arch Street
Philadelphia, PA 19106

For Commonwealth of Virginia:
Director
Virginia Department of Environmental Quality
629 East Main Street
P.O. Box 10009
Richmond, VA 23240-0009

For State of West Virginia:
Director, Division of Air Quality
Department of Environmental Protection
7012 MacCorkle Avenue SE
Charleston, WV 25304

For State of New York:
Bureau Chief
Environmental Protection Bureau
New York Attorney General's Office
120 Broadway
New York, New York 10271

For State of New Jersey:
Administrator
Air and Environmental Quality Compliance and Enforcement
P.O. Box 422
401 East State Street, Floor 4
Trenton, NJ 08625

- and -

Section Chief
Environmental Enforcement
Division of Law
P.O. Box 093
25 Market Street, 7th Floor
Trenton, NJ 08625

For State of Connecticut:
Department Head
Environmental Protection Department
Connecticut Attoreny General's Office
55 Elm Street
Hartford, CT 06106

For VEPCO:
Senior Vice President - Fossil and Hydro
Dominion Energy - Dominion Generation
5000 Dominion Boulevard
Glenn Allen, VA 23060

Any Party may change either the notice recipient or the address for providing notices to it by serving all other parties with a notice setting forth such new notice recipient or address.

187. Procedure for Modification. There shall be no modification of this Decree unless such modification is in writing , is filed with the Court, and either:

(a) bears the written approval of all of the Parties and is approved by the Court, or

(b) is otherwise allowed by applicable law.

188. Continuing Jurisdiction. The Court shall retain jurisdiction of this case after entry of this Consent Decree to enforce compliance with the terms and conditions of this Consent Decree and to take any action necessary or appropriate for its interpretation, construction, execution, or modification. During the term of this Consent Decree, any party may apply to the Court for any relief necessary to construe or effectuate this Consent Decree.

189. Complete Agreement. This Consent Decree constitutes the final, complete, and exclusive agreement and understanding among the parties with respect to the settlement embodied in this Consent Decree. The parties acknowledge that there are no representations, agreements, or understandings relating to the settlement other than those expressly contained in this Consent Decree, including Appendices A ("Coal-Fired Steam-Electric Generating Units Constituting the VEPCO System"), B ("Consent Decree Reporting Form"), and C ("Mitigation Projects that Shall be Completed Under this VEPCO Consent Decree"). Appendices A through C are incorporated into and part of this Consent Decree

190. Non-Severability Absent Re-Adoption by the Parties. If this Consent Decree, in whole or in part, is held invalid by a court vested with jurisdiction to make such a ruling, and if such ruling becomes a final judgment, then after entry of such final judgment, no Party shall be bound to any undertaking that would come due or have continued under this Decree after the date of that final judgment, and the Decree shall be void from the entry of such final judgment. At any time, upon consent of all the Parties, the Parties may preserve that portion of this Decree not held invalid by agreeing, in a writing submitted to this Court, to keep in force that portion of this Decree not held invalid.

191. Citations to Law. Except as expressly provided otherwise by this Decree, provisions of law expressly cited by this Decree shall be construed to mean the provision cited as it is defined under law.

192. Meaning of Terms. Every term expressly defined by this Decree shall have the meaning given to that term by this Decree, and every other term used in this Decree that is a term used under the Act or the regulations implementing the Act shall mean in this Decree what such term means under the Act or those regulations.

193. Calculating and Measuring Performance. Performance standards, emissions limits, and other quantitative standards set by or under this Decree must be met to the number of significant digits in which the standard or limit is expressed. Thus, for example, an Emissions Rate of 0.090 is not met if the actual Emissions Rate is 0.091. VEPCO shall round the fourth significant digit to the nearest third significant digit, or the third significant digit to the second significant digit, depending upon whether the limit is expressed to two or three significant digits. Thus, for example, if an actual Emissions Rate is 0.0904, that shall be reported as 0.090, and shall be in compliance with an Emissions Rate of 0.090, and if an actual Emissions Rate is 0.0905, that shall be reported as 0.091, and shall not be in compliance with an Emissions Rate of 0.090. VEPCO shall collect and report data to the number of significant digits in which the standard or limit is expressed. As otherwise applicable and unles s this Decree expressly directs otherwise, the calculation and measurement procedures established under 40 C.F.R. Parts 75 and 76 apply to the measurement and calculation of NO_x and SO₂ under this Decree.

194. Independent Requirements. Each limit and / or other requirement established by or under this Decree is a separate, independent requirement.

195. Written Statements to be Sent to all Plaintiffs. Notwithstanding any other provision of this Decree, VEPCO shall supply to all Parties to this Decree all notices, reports, applications, elections, and any other written statement that the Decree requires VEPCO to supply to any Party to the Decree.

196. Applicable Law on Data Use Still Applies. Nothing in this Consent Decree alters or waives any applicable law (including, but not limited to, any defenses, entitlements, or clarifications related to the Credible Evidence Rule (62 Fed. Reg. 8314, Feb. 27, 1997)) concerning use of data for any purpose under the Act, generated by the reference methods specified herein or otherwise.

XXX. CONDITIONAL TERMINATION OF ENFORCEMENT, CONTINUATION OF TERMS, AND FIRST RESORT TO TITLE V PERMIT

197. Termination as to Completed Tasks. As soon as VEPCO completes any element of construction required by this Decree or completes any requirement that will not recur, VEPCO may seek termination of that portion of the Decree that dictated such requirement.

198. Conditional Termination of Enforcement through Consent Decree. Once VEPCO:

(A) believes it has successfully completed and commenced successful operation of all pollution controls (new and upgrades) required by Decree;

(B) holds final, Title V Permits -- covering all Units in the VEPCO System -- that include as enforceable permit terms all of the performance and other requirements for the VEPCO System as required by Section X ("Permits"), and

(C) certifies that the date is later than December 31, 2015;

then VEPCO may file a notice with the Court of these facts. Unless within forty-five (45) days after VEPCO files such a notice, any Plaintiff objects to the accuracy of that notice, enforcement based on Decree violations that occurred after the filing of the notice shall be through the applicable Title V Permit and not through this Decree.

199. Resort to Enforcement under this Consent Decree. Notwithstanding paragraph 199, if enforcement of a provision of this Decree cannot be pursued by a party under the applicable Title V permit, or if a Decree requirement was intended to be part of the Title V Permit and did not become or remain part of such permit, then such requirement may be enforced under the terms of this Decree at any time.

SO ORDERED, THIS _________ DAY OF _______________, 2003.

________________________________________

UNITED STATES DISTRICT COURT JUDGE

FOR THE UNITED STATES OF AMERICA:

THOMAS L. SANSONETTI
Assistant Attorney General
Environmental and Natural Resources Division
United States Department of Justice

THOMAS A. MARIANI
Assistant Chief
Environmental Enforcement Section
Environmental and Natural Resources Division
United States Department of Justice

JOHN PETER SUAREZ
Assistant Administrator
Office of Enforcement and Compliance Assurance
United States Environmental Protection Agency

BRUCE C. BUCKHEIT
Director, Air Enforcement Division
Office of Enforcement and Compliance Assurance
United States Environmental Protection Agency

RICHARD ALONSO
Attorney Advisor
Air Enforcement Division
Office of Enforcement and Compliance Assurance
United States Environmental Protection Agency

DONALD S. WELSH
Regional Administrator
Region 3
United States Environmental Protection Agency

FOR THE STATE OF NEW YORK:

ELLIOT SPITZER
Attorney General
State of New York

FOR THE STATE OF NEW JERSEY:

PETER C. HARVEY
Acting Attorney General of New Jersey

FOR THE STATE OF CONNECTICUT:

RICHARD BLUMENTHAL
Attorney General
State of Connecticut

CARMEL A. MOTHERWAY
Assistant Attorney General
State of Connecticut

KIMBERLY P. MASSICOTTE
Assistant Attorney General
State of Connecticut

FOR THE COMMONWEALTH OF VIRGINIA:

________________________________
ROGER L. CHAFFE
Senior Assistant Attorney General
Commonwealth of Virginia

________________________________
ROBERT G. BURNLEY
Director
Department of Environmental Quality
Commonwealth of Virginia

FOR THE STATE OF WEST VIRGINIA:

JOHN BENEDICT
Director
Division of Air Quality
West Virginia Department of Environmental Protection

ROLAND T. HUSON, III
Senior Counsel
Office of Legal Services
West Virginia Department of Environmental Protection

FOR VIRGINIA ELECTRIC AND POWER COMPANY:

EDWARD RIVAS
Sr. Vice President
Fossil and Hydro
Virginia Electric and Power Company

EX-12.1

Exhibit 12.1

Virginia Electric and Power Company
Computation of Ratio of Earnings to Fixed Charges
(millions of dollars)

			Years Ended
			12 months ended March 31, 2003	2002	2001	2000	1999	1998
Earnings, as defined:
	Earnings before income taxes and minority interests in consolidated subsidiaries		$ 1,448	$1,198	$733	$  837	$  743	$ 387
	Fixed charges included in the determination of net income		303	304	310	303	297	325
		Total earnings, as defined	$ 1,751	$ 1,502	$ 1,043	$ 1,140	$ 1,040	$ 712
	Fixed charges, as defined:
		Interest charges	$ 310	$ 311	$ 320	$ 297	$ 290	$ 319
		Rental interest factor	10	10	10	6	7	6
		Total fixed charges, as defined	$ 320	$ 321	$ 330	$ 303	$ 297	$ 325
Ratio of Earnings to Fixed Charges			5.47	4.68	3.16	3.76	3.50	2.19

EX-12.2

Exhibit 12.2

Virginia Electric and Power Company
Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends

(millions of dollars)

			Years Ended
			12 months ended March 31, 2003	2002	2001	2000	1999	1998
Earnings, as defined:
	Earnings before income taxes and minority interests in consolidated subsidiaries		$ 1,448	$  1,198	$  733	$  837	$   743	$ 387
	Fixed charges included in the determination of net income		303	304	310	303	297	325
		Total earnings, as defined	$ 1,751	$ 1,502	$ 1,043	$ 1,140	$ 1,040	$ 712
	Fixed charges, as defined:
		Interest charges	$ 310	$ 311	$ 320	$ 297	$ 290	$ 319
		Preference security dividend requirements of consolidated subsidiaries	24	25	38	54	57	61
		Rental interest factor	10	10	10	6	7	6
		Total fixed charges, as defined	$ 344	$ 346	$ 368	$ 357	$ 354	$ 386
Ratio of Earnings to Fixed Charges and Preferred Dividends			5.09	4.34	2.83	3.19	2.94	1.85

EX-99.1

Exhibit 99.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Thomas F. Farrell, II, President and Chief Executive Officer of Virginia Electric and Power Company (the Company), certify that:

1. the Quarterly Report on Form 10-Q of the Company to which this certification is an exhibit for the quarter ended March 31, 2003 (the "Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).
2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of March 31, 2003 and for the period then ended.

     /s/ Thomas F. Farrell                      
Thomas F. Farrell
President and Chief Executive Officer
May 9, 2003

A signed original of this written statement required by Section 906 has been provided to Virginia Electric and Power Company and will be retained by Virginia Electric and Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.2

Exhibit 99.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Jay L. Johnson, President and Chief Executive Officer of Virginia Electric and Power Company (the Company), certify that:

1. the Quarterly Report on Form 10-Q of the Company to which this certification is an exhibit for the quarter ended March 31, 2003 (the "Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).
2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of March 31, 2003 and for the period then ended.

     /s/ Jay L. Johnson                          
Jay L. Johnson
President and Chief Executive Officer
May 9, 2003

A signed original of this written statement required by Section 906 has been provided to Virginia Electric and Power Company and will be retained by Virginia Electric and Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.3

Exhibit 99.3

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Paul D. Koonce, Chief Executive Officer - Transmission of Virginia Electric and Power Company (the Company), certify that:

1. the Quarterly Report on Form 10-Q of the Company to which this certification is an exhibit for the quarter ended March 31, 2003 (the "Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).
2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of March 31, 2003 and for the period then ended.

      /s/ Paul D. Koonce                          
Paul D. Koonce
Chief Executive Officer - Transmission
May 9, 2003

A signed original of this written statement required by Section 906 has been provided to Virginia Electric and Power Company and will be retained by Virginia Electric and Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.4

Exhibit 99.4

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark F. McGettrick, President and Chief Executive Officer - Generation of Virginia Electric and Power Company (the Company), certify that:

1. the Quarterly Report on Form 10-Q of the Company to which this certification is an exhibit for the quarter ended March 31, 2003 (the "Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).
2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of March 31, 2003 and for the period then ended.

     /s/ Mark F. McGettrick                     
Mark F. McGettrick
President and Chief Executive Officer -
Generation
May 9, 2003

A signed original of this written statement required by Section 906 has been provided to Virginia Electric and Power Company and will be retained by Virginia Electric and Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.5

Exhibit 99.5

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, G. Scott Hetzer, Senior Vice President and Treasurer of Virginia Electric and Power Company (the Company), certify that:

1. the Quarterly Report on Form 10-Q of the Company to which this certification is an exhibit for the quarter ended March 31, 2003 (the "Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).
2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of March 31, 2003 and for the period then ended.

      /s/ G. Scott Hetzer                        
G. Scott Hetzer
Senior Vice President and Treasurer
May 9, 2003

A signed original of this written statement required by Section 906 has been provided to Virginia Electric and Power Company and will be retained by Virginia Electric and Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.6

Exhibit 99.6

VIRGINIA ELECTRIC AND POWER COMPANY

CONDENSED CONSOLIDATED EARNINGS STATEMENTS
(Unaudited)

	Three Months Ended	Nine Months Ended
	March 31, 2003	December 31, 2002
	(millions)
Operating Revenue	$1,511	$3,820
Operating Expenses	959	2,672
Income from operations	552	1,148
Other income	14	25
Interest and related charges	74	218
Income before income taxes	492	955
Income taxes	186	336
Income before cumulative effect of changes in   accounting principle	306	619
Cumulative effect of changes in accounting principle   (net of income taxes of $51)	84	--
Net income	390	619
Preferred dividends	3	12
Balance available for common stock	$  387	$  607

The condensed consolidated earnings statement for the three months ended March 31, 2003 reflects the adoption of two new accounting standards, effective January 1, 2003. These standards are Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, and Emerging Issues Task Force Issue No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. The condensed consolidated earnings statement for the nine months ended December 31, 2003, which was prepared under different accounting policies regarding the accounting matters covered by the aforementioned new standards, may not combined with the condensed consolidated earnings statement for the three months ended March 31, 2003, under generally accepted accounting principles.