ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
(millions)
Operating Revenue		$	1,323		$	1,285		$	2,656		$	2,643
Operating Expenses
Electric fuel and energy purchases			555			505			1,112			979
Purchased electric capacity			109			114			226			242
Other energy-related commodity purchases			8			7			18			20
Other operations and maintenance:
External suppliers			207			146			396			400
Affiliated suppliers			81			72			158			144
Depreciation and amortization			135			132			267			263
Other taxes			43			47			88			93
Total operating expenses			1,138			1,023			2,265			2,141
Income from operations			185			262			391			502
Other income			17			14			41			29
Interest and related charges:
Interest expense			63			72			133			135
Interest expense—junior subordinated notes payable to affiliated trust			7			7			15			15
Total interest and related charges			70			79			148			150
Income from continuing operations before income tax expense			132			197			284			381
Income tax expense			46			73			101			142
Income from continuing operations			86			124			183			239
Loss from discontinued operations (net of income tax benefit of $32 and $89 in 2005)			—			(67	)		—			(160	)
Net Income			86			57			183			79
Preferred dividends			4			4			8			8
Balance available for common stock		$	82		$	53		$	175		$	71

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

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CONSOLIDATED BALANCE SHEETS

(Unaudited)

		June 30, 2006			December 31, 2005(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents		$	20		$	54
Customer accounts receivable (less allowance for doubtful accounts of $7 at    both dates)			682			700
Other receivables (less allowance for doubtful accounts of $9 at both dates)			46			67
Inventories			506			443
Prepayments			23			36
Other			87			66
Total current assets			1,364			1,366
Investments
Nuclear decommissioning trust funds			1,182			1,166
Other			22			22
Total investments			1,204			1,188
Property, Plant and Equipment
Property, plant and equipment			20,665			20,317
Accumulated depreciation and amortization			(8,249	)		(8,055	)
Total property, plant and equipment, net			12,416			12,262
Deferred Charges and Other Assets
Regulatory assets			282			326
Other			273			307
Total deferred charges and other assets			555			633
Total assets		$	15,539		$	15,449

(1) The Consolidated Balance Sheet at December 31, 2005 has been derived from the audited Consolidated Financial Statements at that date.

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

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

		June 30, 2006			December 31, 2005(1)
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year		$	667		$	618
Short-term debt			249			905
Accounts payable			349			415
Payables to affiliates			65			42
Affiliated current borrowings			201			12
Accrued interest, payroll and taxes			440			288
Other			220			212
Total current liabilities			2,191			2,492
Long-Term Debt
Long-term debt			3,584			3,256
Junior subordinated notes payable to affiliated trust			412			412
Notes payable—other affiliates			220			220
Total long-term debt			4,216			3,888
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits			2,221			2,250
Asset retirement obligations			857			834
Regulatory liabilities			416			409
Other			125			86
Total deferred credits and other liabilities			3,619			3,579
Total liabilities			10,026			9,959
Commitments and Contingencies (see Note 10)
Preferred Stock Not Subject to Mandatory Redemption			257			257
Common Shareholder’s Equity
Common stock—no par, 300,000 shares authorized; 198,047 shares outstanding			3,388			3,388
Other paid-in capital			887			886
Retained earnings			878			842
Accumulated other comprehensive income			103			117
Total common shareholder's equity			5,256			5,233
Total liabilities and shareholder's equity		$	15,539		$	15,449

(1) The Consolidated Balance Sheet at December 31, 2005 has been derived from the audited Consolidated Financial Statements at that date.

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

		Six Months Ended June 30,
		2006			2005
(millions)
Operating Activities
Net income		$	183		$	79
Adjustments to reconcile net income to net cash provided by operating activities:
Net realized and unrealized derivative (gains)/losses			(4	)		57
Depreciation and amortization			307			298
Deferred income taxes and investment tax credits, net			(29	)		(18	)
Deferred fuel expenses, net			56			50
Gain on sale of emissions allowances			(20	)		(53	)
Other adjustments to net income			(21	)		(65	)
Changes in:
Accounts receivable			37			145
Affiliated accounts receivable and payable			25			(59	)
Inventories			(63	)		35
Prepaid pension cost			32			28
Accounts payable			(60	)		36
Accrued interest, payroll and taxes			152			5
Other operating assets and liabilities			79			79
Net cash provided by operating activities			674			617
Investing Activities
Plant construction and other property additions			(421	)		(361	)
Purchases of nuclear fuel			(60	)		(61	)
Purchases of securities			(267	)		(153	)
Proceeds from sales of securities			256			125
Proceeds from sale of emissions allowances			20			37
Other			2			26
Net cash used in investing activities			(470	)		(387	)
Financing Activities
Issuance (repayment) of short-term debt, net			(655	)		295
Issuance (repayment) of affiliated current borrowings, net			190			(249	)
Issuance of long-term debt			1,000			—
Repayment of long-term debt			(612	)		(16	)
Common dividend payments			(139	)		(238	)
Preferred dividend payments			(8	)		(8	)
Other			(14	)		—
Net cash used in financing activities			(238	)		(216	)
Increase (decrease) in cash and cash equivalents			(34	)		14
Cash and cash equivalents at beginning of period			54			2
Cash and cash equivalents at end of period		$	20		$	16
Noncash Financing Activities:
Assumption of debt related to the acquisition of a non-utility generating facility		$	—		$	62
Issuance of debt in exchange for electric distribution assets			—			8

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1.   Nature of Operations

Virginia Electric and Power Company (the Company), a Virginia public service company, is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). We are a regulated public utility that generates, transmits and distributes electricity within an area of approximately 30,000 square miles in Virginia and northeastern North Carolina. We serve approximately 2.3 million retail customer accounts, including governmental agencies and wholesale customers such as rural electric cooperatives and municipalities. The Virginia service area comprises about 65% of Virginia’s total land area but accounts for over 80% of its population. On May 1, 2005, we became a member of PJM Interconnection, LLC (PJM), a regional transmission organization (RTO). As a result, we integrated our control area into the PJM wholesale electricity markets.

As discussed in Note 7, on December 31, 2005, we completed a transfer of our indirect wholly-owned subsidiary, Virginia Power Energy Marketing, Inc. (VPEM), to Dominion through a series of dividend distributions, in exchange for a capital contribution. VPEM provides fuel and price risk management services to us and other Dominion affiliates and engages in energy trading activities. Through VPEM, we had trading relationships beyond the geographic limits of our retail service territory and bought and sold natural gas, electricity and other energy-related commodities. As a result of the transfer, VPEM’s results of operations are no longer included in our Consolidated Financial Statements, and our Consolidated Statements of Income for periods prior to the transfer have been adjusted to reflect VPEM as a discontinued operation. In addition, the discontinued operations of VPEM are now included in our Corporate segment results.

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

The terms “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one of Virginia Electric and Power Company’s consolidated subsidiaries or operating segments or the entirety of Virginia Electric and Power Company, including our Virginia and North Carolina operations and our consolidated subsidiaries.

Note 2.   Significant Accounting Policies

As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), our accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). These unaudited Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2005 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2006.

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

We make certain estimates and assumptions in preparing our Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses for the periods presented. Actual results may differ from those estimates.

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

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We report certain contracts and instruments at fair value in accordance with GAAP. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, we estimate fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. See Note 2 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005 for more discussion of our 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, electric fuel and energy purchases and other factors.

Certain amounts in our 2005 Consolidated Financial Statements and Notes have been reclassified to conform to the 2006 presentation.

Note 3.   Recently Issued Accounting Standards

FIN 48

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). FIN 48 establishes standards for measurement and recognition in financial statements of positions taken by an entity in its income tax returns. In addition, FIN 48 requires new disclosures about positions taken by an entity in its tax returns that are not recognized in its financial statements, information about potential significant changes in estimates related to tax positions and descriptions of open tax years by major jurisdiction. The provisions of FIN 48 will become effective for us beginning January 1, 2007, with the cumulative effect of the change in accounting principle recorded as an adjustment to retained earnings. We are currently evaluating the impact that FIN 48 will have on our results of operations and financial condition.

Note 4.   Operating Revenue

Our operating revenue consists of the following:

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
(millions)
Regulated electric sales		$	1,283		$	1,245		$	2,581		$	2,567
Other			40			40			75			76
Total operating revenue		$	1,323		$	1,285		$	2,656		$	2,643

Note 5.   Comprehensive Income

The following table presents total comprehensive income:

 

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
(millions)
Net income		$	86		$	57		$	183		$	79
Other comprehensive income (loss):
Net other comprehensive loss associated with       effective portion of changes in fair value of       derivatives designated as cash flow hedges, net       of taxes and amounts reclassified to earnings			—			(2	)		(7	)		(15	)
Other(1)			(17	)		8			(7	)		(8	)
Other comprehensive income (loss)			(17	)		6			(14	)		(23	)
Total comprehensive income		$	69		$	63		$	169		$	56

(1)	Primarily represents unrealized gains (losses) on investments held in nuclear decommissioning trusts.

Note 6.   Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products, as well as currency exchange and interest rate risks of our business operations. We use derivative instruments to manage our exposure to certain of these risks and designate derivative instruments as either fair value or cash flow hedges for accounting purposes as allowed by Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities.

Selected information about our hedge accounting activities follows:

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
(millions)
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges		$	—		$	2		$	—		$	2
Cash flow hedges			(1	)		—			(1	)		—
Net ineffectiveness		$	(1	)	$	2		$	(1	)	$	2

Gains and losses on hedging instruments that were excluded from the measurement of ineffectiveness and included in net income for the three and six months ended June 30, 2006 and 2005 were not material.

The following table presents selected information related to cash flow hedges included in accumulated other comprehensive income (AOCI) in our Consolidated Balance Sheet at June 30, 2006:

		AOCI After-Tax			Portion Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Electricity		$	(2	)	$	(2	)		3 months
Gas			(4	)		(4	)		3 months
Interest rate			1			—			112 months
Foreign currency			18			8			17 months
Total		$	13		$	2

The amounts that will be 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 and will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign exchange rates.

Note 7.   Discontinued Operations—VPEM Transfer

On December 31, 2005, we completed the transfer of VPEM to Dominion through a series of dividend distributions. This resulted in a transfer of our negative investment in VPEM to Dominion in exchange for a capital contribution of $633 million. No gain or loss was recognized on the transfer.

VPEM provides fuel and price risk management services to us by acting as an agent for one of our indirect wholly-owned subsidiaries. VPEM also engages in energy trading activities and provides price risk management services to other Dominion affiliates through the use of derivative contracts. While we owned VPEM, certain of these derivative contracts were reported at fair value on our Consolidated Balance Sheets, with changes in fair value reflected in earnings. These price risk management activities performed on behalf of Dominion affiliates generated derivative gains and losses that affected our Consolidated Financial Statements.

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As a result of the transfer, VPEM’s results of operations are no longer included in our Consolidated Financial Statements, and our Consolidated Statements of Income for the three and six months ended June 30, 2005 have been adjusted to reflect VPEM as a discontinued operation, on a net basis. In the three and six months ended June 30, 2005, our discontinued operations included operating revenue of $190 million and $429 million, respectively, and a loss before income taxes of $99 million and $249 million, respectively.

VPEM’s 2005 results included the following affiliated transactions:

		Three Months Ended June 30, 2005			Six Months Ended June 30, 2005
(millions)
Purchases of natural gas, gas transportation and storage services from affiliates		$	206		$	487
Sales of natural gas to affiliates			275			498
Net realized gains on affiliated commodity derivative contracts			2			13
Affiliated interest and related charges			4			7

Note 8.   Variable Interest Entities

Certain variable pricing terms in some of our long-term power and capacity contracts cause those contracts to be considered potential variable interests in the counterparties. As discussed in Note 14 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005, three potential VIEs with which we have existing power purchase agreements (signed prior to December 31, 2003), have not provided sufficient information for us to perform our evaluation under FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (FIN 46R).

As of June 30, 2006, the requested information has not been received from the three remaining potential VIEs. We will continue our efforts to obtain information and will complete an evaluation of our relationship with each of these potential VIEs if sufficient information is ultimately obtained. We have remaining purchase commitments with these three potential VIE supplier entities of $2.0 billion at June 30, 2006. We paid $44 million and $48 million for electric generation capacity and $41 million and $34 million for electric energy to these entities in the three months ended June 30, 2006 and 2005, respectively. We paid $94 million and $101 million for electric generation capacity and $77 million and $80 million for electric energy to these entities in the six months ended June 30, 2006 and 2005, respectively.

During 2005, we entered into four long-term contracts with unrelated limited liability corporations (LLCs) to purchase synthetic fuel produced from coal. Certain variable pricing terms in the contracts protect the equity holders from variability in the cost of their coal purchases, and therefore, the LLCs were determined to be VIEs. After completing our FIN 46R analysis, we concluded that although our interests in the contracts, as a result of their pricing terms, represent variable interests in the LLCs, we are not the primary beneficiary. We paid $104 million and $43 million to the LLCs for coal and synthetic fuel produced from coal in the three months ended June 30, 2006 and 2005, respectively, and $215 million and $63 million in the six months ended June 30, 2006 and 2005, respectively. We are not subject to any risk of loss from the contractual arrangements, as our only obligation to the VIEs is to purchase the coal and synthetic fuel that the VIEs provide according to the terms of the applicable purchase contracts.

In accordance with FIN 46R, we consolidate a variable interest lessor entity through which we have financed and leased a power generation project. Our Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005 reflect net property, plant and equipment of $342 million and $348 million, respectively, and $370 million of debt related to this entity. The debt is nonrecourse to us and is secured by the entity’s property, plant and equipment.

Note 9.   Significant Financing Transactions

Joint Credit Facilities and Short-term Debt

We use short-term debt, primarily commercial paper, to fund working capital requirements and as a bridge to long-term debt financing. The level of our borrowings may vary significantly during the course of the year, depending

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upon the timing and amount of cash requirements not satisfied by cash from operations. In February 2006, we entered into a $3.0 billion five-year revolving credit facility with Dominion and Consolidated Natural Gas Company (CNG), a wholly-owned subsidiary of Dominion. The credit facility is scheduled to terminate in February 2011. This credit facility is being used for working capital, as support for the combined commercial paper programs of Dominion, CNG and us and other general corporate purposes. This credit facility can also be used to support up to $1.5 billion of letters of credit.

At June 30, 2006, total outstanding commercial paper supported by the joint credit facility was $998 million, of which our borrowings were $249 million. At June 30, 2006, total outstanding letters of credit supported by the joint credit facility were $653 million, of which less than $1 million was issued on our behalf.

At June 30, 2006, capacity available under the credit facility was $1.3 billion.

Long-term Debt

In January 2006, we issued $450 million of 5.4% senior notes that mature in 2016 and $550 million of 6.0% senior notes that mature in 2036. We used the proceeds from this issuance to repay short-term debt incurred to redeem our $512 million callable mortgage bonds and a portion of our maturing long-term debt.

In February 2006, we entered into a $200 million five-year stand-alone credit facility. This credit facility is used to support our long-term variable rate tax-exempt financings and is scheduled to terminate in February 2011.

During the six months ended June 30, 2006, we repaid $612 million of our long-term debt.

Note 10.   Commitments and Contingencies

Other than the matters discussed below, there have been no significant developments regarding commitments and contingencies as disclosed in Note 21 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005, or Note 9 to the Consolidated Financial Statements in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2006, nor have any significant new matters arisen during the quarter ended June 30, 2006.

Environmental Matters

In 1987, we and a number of other entities were identified by the Environmental Protection Agency (EPA) as potentially responsible parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. In 2003, the EPA issued its Certificate of Completion of remediation for the Kentucky site. Future costs for the Kentucky site will be limited to minor operations and maintenance expenditures. Regarding the Pennsylvania site, in March 2006, a federal district court approved three consent decrees between the United States and the PRPs, under which we and certain other PRPs, all of which are utilities, will perform the site remediation. The remediation costs are expected to be in the range of $11 million to $18 million, the majority of which are to be paid by the non-utility site owners. After evaluating the impact of these actions, we have reduced our current reserve from $2 million to less than $1 million to meet our potential obligations at these two sites. We generally seek to recover our costs associated with environmental remediation from third party insurers. At June 30, 2006, no pending or possible insurance claims were recognized as an asset or offset against obligations.

Guarantees and Surety Bonds

As of June 30, 2006, we had issued less than $1 million of guarantees primarily to support commodity transactions of our subsidiaries. We had also purchased $16 million of surety bonds for various purposes, including providing workers’ compensation coverage and obtaining licenses, permits and rights-of-way. Under the terms of surety bonds, we are obligated to indemnify the respective surety bond company for any amounts paid.

Note 11.   Credit Risk

We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our June 30, 2006 provision for credit losses, that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

We sell electricity and provide distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of our

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customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers.

Our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At June 30, 2006, our gross credit exposure totaled $77 million. Of this amount, 87% related to a single counterparty; however, the entire balance is with investment grade entities. We held no collateral for these transactions at June 30, 2006.

Note 12.   Related Party Transactions

We engage in related party transactions primarily with affiliates (Dominion subsidiaries). Our accounts receivable and payable balances with affiliates are settled based on contractual terms on a monthly basis, depending on the nature of the underlying transactions. We are included in Dominion’s consolidated federal income tax return and participate in certain Dominion benefit plans. A discussion of significant related party transactions follows.

Transactions with Affiliates

We transact with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business.

At June 30, 2006, our Consolidated Balance Sheets includes derivative liabilities with affiliates of $7 million. There were no derivative liabilities with affiliates at December 31, 2005. Unrealized gains or losses, representing the effective portion of the changes in fair value of those derivative contracts that have been designated as cash flow hedges, are included in AOCI on our Consolidated Balance Sheets.

Dominion Resources Services, Inc. (Dominion Services) provides accounting, legal and certain administrative and technical services to us. In addition, we provide certain services to affiliates, including charges for facilities and equipment usage.

The transactions with Dominion Services and other affiliates are detailed below:

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
(millions)
Commodity purchases from affiliates		$	46		$	73		$	80		$	121
Commodity sales to affiliates			—			—			3			4
Services provided by affiliates			81			72			158			144
Services provided to affiliates			6			6			12			13

Transactions with Dominion

We have borrowed funds from Dominion under both short-term and long-term borrowing arrangements. At June 30, 2006 and December 31, 2005, our outstanding borrowings, net of repayments, under the Dominion money pool for our nonregulated subsidiaries totaled $201 million and $12 million, respectively. There were no short-term demand note borrowings at June 30, 2006 or December 31, 2005. At June 30, 2006 and December 31, 2005, our borrowings from Dominion under a long-term note totaled $220 million. We incurred net interest charges related to our borrowings from Dominion of $1 million and $2 million in the three months ended June 30, 2006 and 2005, respectively, and $3 million for each of the six month periods ended June 30, 2006 and 2005.

Note 13.   Operating Segments

We are organized primarily on the basis of products and services sold in the United States. The majority of our revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among our Delivery, Energy and Generation segments. We manage our operations through the following segments:

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Delivery includes our regulated electric distribution and customer service business. The Delivery segment is subject to cost-of-service rate regulation and accordingly, applies SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.

Energy includes our tariff-based electric transmission operations, which are subject to cost-of-service rate regulation and accordingly, applies SFAS No. 71.

Generation includes our portfolio of electric generating facilities and our energy supply operations.

Corporate includes our corporate and other functions, as well as the discontinued operations of VPEM. The contribution to net income by our primary operating segments is determined based on a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments and are instead reported in the Corporate segment. For the six months ended June 30, 2006 and 2005, we reported net expenses of $4 million and $213 million, respectively, in our Corporate segment.

The net expenses in 2006 reflect a $7 million ($4 million after-tax) charge resulting from the write-off of certain assets no longer in use at one of our electric generating facilities, attributable to our Generation segment.

The net expenses in 2005 included $160 million of losses incurred in the six months ended June 30, 2005 relating to the discontinued operations of VPEM, as well as the following items attributable to our Generation segment:

 

·	A $77 million ($47 million after-tax) charge resulting from the termination of a long-term power purchase agreement; and

·	A $13 million ($8 million after-tax) charge related to our interest in a long-term power tolling contract that was divested in 2005.

The following table presents segment information pertaining to our operations:

		Delivery			Energy			Generation			Corporate			Consolidated Total
(millions)
Three Months Ended June 30, 2006
Operating revenue		$	287		$	52		$	983		$	1		$	1,323
Net income (loss)			66			16			8			(4	)		86
Three Months Ended June 30, 2005
Operating revenue		$	272		$	47		$	965		$	1		$	1,285
Loss from discontinued operations, net of tax			—			—			—			(67	)		(67	)
Net income (loss)			59			13			54			(69	)		57
Six Months Ended June 30, 2006
Operating revenue		$	576		$	104		$	1,976		$	—		$	2,656
Net income (loss)			133			33			21			(4	)		183
Six Months Ended June 30, 2005
Operating revenue		$	571		$	102		$	1,965		$	5		$	2,643
Loss from discontinued operations, net of tax			—			—			—			(160	)		(160	)
Net income (loss)			141			28			123			(213	)		79

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VIRGINIA ELECTRIC AND POWER COMPANY

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 Electric and Power Company. MD&A should be read in conjunction with our Consolidated Financial Statements. The terms “Virginia Power,” “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one of Virginia Electric and Power Company’s consolidated subsidiaries or operating segments, or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries. We are a wholly-owned subsidiary of Dominion.

Contents of MD&A

Our MD&A consists of the following information:

·	Forward-Looking Statements

·	Accounting Matters

·	Results of Operations

·	Segment Results of Operations

·	Sources and Uses of Cash

·	Future Issues and Other Matters

Forward-Looking Statements

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

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

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

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

·	State and federal legislative and regulatory developments, including deregulation and changes in environmental and other laws and regulations to which we are subject;

·	Cost of environmental compliance;

·	Risks associated with the operation of nuclear facilities;

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

·	Capital market conditions, including price risk due to marketable securities held as investments in nuclear  decommissioning and benefit plan trusts;

·	Fluctuations in interest rates;

·	Changes in rating agency requirements or credit ratings and the effect on availability and cost of capital;

·	Changes in financial or regulatory accounting principles or policies imposed by governing bodies;

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

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

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

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

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in this report and in our Annual Report on Form 10-K for the year ended December 31, 2005 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2006.

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

Accounting Matters

Critical Accounting Policies and Estimates

As of June 30, 2006, there have been no significant changes with regard to critical accounting policies and estimates as disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2005. The policies disclosed included the accounting for: derivative contracts at fair value, long-lived asset impairment testing, asset retirement obligations, regulated operations and income taxes.

Other

FIN 48

In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). FIN 48 establishes standards for measurement and recognition in financial statements of positions taken by an entity in its income tax returns. In addition, FIN 48 requires new disclosures about positions taken by an entity in its tax returns that are not recognized in its financial statements, information about potential significant changes in estimates related to tax positions and descriptions of open tax years by major jurisdiction. The provisions of FIN 48 will become effective for us beginning January 1, 2007, with the cumulative effect of the change in accounting principle recorded as an adjustment to retained earnings. We are currently evaluating the impact that FIN 48 will have on our results of operations and financial condition.

Results of Operations

Presented below is a summary of our consolidated results for the quarter and year-to-date periods ended June 30, 2006 and 2005:

		Second Quarter									Year-To-Date
		2006			2005			$ Change			2006			2005			$ Change
(millions)
Net income		$	86		$	57		$	29		$	183		$	79		$	104

Overview

Second Quarter 2006 vs. 2005

Net income increased 51% to $86 million. Favorable drivers include an increase in regulated electric sales revenue resulting from customer growth and other factors and the absence of $67 million of after-tax losses incurred in 2005 by the discontinued operations of VPEM. Unfavorable drivers include the impact of higher commodity prices on fuel and purchased power expenses and a decrease in gains recognized from the sale of emissions allowances.

Year-To-Date 2006 vs. 2005

Net income increased 132% to $183 million. Favorable drivers include the absence of $160 million of after-tax losses incurred in 2005 by the discontinued operations of VPEM and the absence of a 2005 charge resulting from the termination of a long-term power purchase agreement. Unfavorable drivers include the impact of higher commodity prices on fuel and purchased power expenses and a decrease in gains recognized from the sale of emissions allowances.

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Analysis of Consolidated Operations

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

		Second Quarter									Year-To-Date
		2006			2005			$ Change			2006			2005			$ Change
(millions)
Operating Revenue		$	1,323		$	1,285		$	38		$	2,656		$	2,643		$	13
Operating Expenses
Electric fuel and energy purchases			555			505			50			1,112			979			133
Purchased electric capacity			109			114			(5	)		226			242			(16	)
Other energy-related commodity purchases			8			7			1			18			20			(2	)
Other operations and maintenance			288			218			70			554			544			10
Depreciation and amortization			135			132			3			267			263			4
Other taxes			43			47			(4	)		88			93			(5	)
Other income			17			14			3			41			29			12
Interest and related charges			70			79			(9	)		148			150			(2	)
Income tax expense			46			73			(27	)		101			142			(41	)
Loss from discontinued operations, net of tax			—			(67	)		67			—			(160	)		160

An analysis of our results of operations for the second quarter and year-to-date periods of 2006 compared to the second quarter and year-to-date periods of 2005 follows:

Second Quarter 2006 vs. 2005

Operating Revenue increased 3% to $1.3 billion, reflecting the combined effects of:

·	A $22 million increase attributable to variations in rates resulting from changes in customer usage patterns and sales mix and other factors;

·	An $18 million increase due to new customer connections; and

·	A $15 million increase due to the impact of a comparatively higher fuel rate in certain customer jurisdictions which was offset by a comparable increase in Electric fuel and energy  purchases expense; partially offset by

·	A $16 million decrease associated with milder weather.

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 10% to $555 million, primarily due to higher commodity prices, including purchased power.

Other operations and maintenance expense increased 32% to $288 million, primarily reflecting:

·	A $40 million decrease in gains from the sale of emissions allowances;

·	A $17 million increase in outage costs primarily due to scheduled outages of certain of our electric generating facilities;

·	A $12 million increase resulting from higher incentive-based compensation, wages and pension and medical benefits; and

·	A $7 million charge resulting from the write-off of certain assets no longer in use at one of our electric generating facilities.

Other income increased 21% to $17 million, primarily reflecting a $5 million increase in net realized gains (including investment income) associated with nuclear decommissioning trust fund investments.

Interest and related charges decreased 11% to $70 million, primarily due to a reduction in interest accrued on tax deficiencies reflecting the resolution of certain issues with tax authorities.

Loss from discontinued operations reflects the losses incurred in 2005 by the discontinued operations of VPEM.

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Year-To-Date 2006 vs. 2005

Operating Revenue increased 1% to $2.7 billion, reflecting the combined effects of:

·	A $39 million increase due to new customer connections;

·	A $36 million increase due to the impact of a comparatively higher fuel rate in certain customer jurisdictions which was offset by a comparable increase in Electric fuel and energy purchases expense; and

·	A $24 million increase attributable to rate variations resulting from changes in customer usage patterns and sales mix and other factors; largely offset by

·	An $82 million decrease associated with milder weather.

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 14% to $1.1 billion, primarily due to higher commodity prices, including purchased power.

Purchased electric capacity expense decreased 7% to $226 million, primarily due to scheduled capacity reductions for certain long-term power purchase contracts, as well as the termination of a long-term power purchase agreement in connection with the purchase of the related generating facility in February 2005.

Other operations and maintenance expense increased 2% to $554 million, primarily reflecting:

·	A $33 million decrease in gains from the sale of emissions allowances;

·	A $23 million increase in outage costs primarily due to scheduled outages of certain of our electric generating facilities;

·	A $16 million increase resulting from higher incentive-based compensation, wages, and pension and medical benefits;

·	A $7 million increase related to storm restorations associated with our distribution operations; and

·	A $7 million charge resulting from the write-off of certain assets no longer in use at one of our electric generating facilities; partially offset by

·	A $31 million benefit related to financial transmission rights (FTRs) granted by PJM used to offset congestion costs associated with PJM spot market activity, which are included in Electric fuel and energy purchases expense; and

·	A net benefit from the absence of the following items recognized in 2005:

·	A $77 million charge resulting from the termination of a long-term power purchase agreement; partially offset by

·	A $25 million net benefit resulting from the establishment of certain regulatory assets in connection with the settlement of a North Carolina rate case.

Other income increased 41% to $41 million, primarily reflecting an $11 million increase in net realized gains (including investment income) associated with nuclear decommissioning trust fund investments.

Loss from discontinued operations reflects the losses incurred in 2005 by the discontinued operations of VPEM.

Segment Results of Operations

Presented below is a summary of contributions by our operating segments to net income for the quarter and year-to-date periods ended June 30, 2006 and 2005:

		Second Quarter									Year-To-Date
		2006			2005			$ Change			2006			2005			$ Change
(millions)
Delivery		$	66		$	59		$	7		$	133		$	141		$	(8	)
Energy			16			13			3			33			28			5
Generation			8			54			(46	)		21			123			(102	)
Primary operating segments			90			126			(36	)		187			292			(105	)
Corporate			(4)			(69)			65			(4)			(213	)		209
Consolidated		$	86		$	57		$	29		$	183		$	79		$	104

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Delivery

Delivery includes our electric distribution system and customer service operations. Presented below are operating statistics related to our Delivery operations:

		Second Quarter									Year-To-Date
		2006			2005			% Change			2006			2005			% Change
Electricity delivered (million mwhrs)			18.7			18.6			1	%		38.2			38.5			(1	)%
Degree days (electric service area):
Cooling(1)			396			370			7			409			370			11
Heating(2)			245			355			(31	)		2,041			2,466			(17	)
Electric delivery customer accounts(3)			2,325			2,283			2			2,325			2,283			2

mwhrs = megawatt hours

(1)	Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.

(2)	Heating degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is less than 65 degrees.

(3)	In thousands, at period end.

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

		Second Quarter			Year-To-Date
		2006 vs. 2005			2006 vs. 2005
		Increase (Decrease)			Increase (Decrease)
(millions)
Regulated electric sales:
Weather		$	(2	)	$	(11	)
Customer growth			3			6
2005 North Carolina rate case settlement			—			(6	)
Other(1)			6			3
Change in net income contribution		$	7		$	(8	)

(1)	Other factors including changes in customer usage.

Energy

Energy includes our electric transmission operations. Presented below, on an after-tax basis, are the key factors impacting Energy’s net income contribution:

		Second Quarter			Year-To-Date
		2006 vs. 2005			2006 vs. 2005
		Increase (Decrease)			Increase (Decrease)
(millions)
RTO start-up and integration costs(1)		$	—		$	4
Regulated electric sales:
Weather			—			(2	)
Customer growth			—			1
Other(2)			3			2
Change in net income contribution		$	3		$	5

(1)	Reflects the absence of a charge incurred in 2005 for the write-off of certain previously deferred start-up and integration costs associated with joining an RTO.

(2)	Other factors including changes in customer usage.

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Generation

Generation includes our portfolio of electric generating facilities, power purchase agreements and energy supply operations. Presented below are operating statistics related to our Generation operations:

		Second Quarter									Year-To-Date
		2006			2005			% Change			2006			2005			% Change
Electricity supplied (million mwhrs)			18.7			18.6			1	%		38.2			38.5			(1	)%

mwhrs = megawatt hours

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

		Second Quarter			Year-To-Date
		2006 vs. 2005			2006 vs. 2005
		Increase (Decrease)			Increase (Decrease)
(millions)
Sale of emissions allowances		$	(25	)	$	(21	)
Fuel expenses in excess of rate recovery			(18	)		(50	)
Energy supply margin(1)			(7	)		(2	)
Outage costs			(4	)		(14	)
Regulated electric sales:
Weather			(5	)		(24	)
Customer growth			5			11
2005 North Carolina rate case settlement			—			(10	)
Interest expense			4			—
Other(2)			4			8
Change in net income contribution		$	(46	)	$	(102	)

(1)	Primarily reflects a reduced benefit from FTRs in excess of congestion costs.

(2)	Other factors including a reduction in capacity expenses and an increase in net realized gains (including investment income) associated with nuclear decommissioning trust fund investments.

Corporate

Corporate includes our corporate and other functions, as well as the discontinued operations of VPEM. Presented below are the Corporate segment’s after-tax results.

		Second Quarter						Year-To-Date
		2006			2005			2006			2005
(millions)
VPEM discontinued operations		$	—		$	(67	)	$	—		$	(160	)
Specific items attributable to operating segments			(4	)		(2	)		(4	)		(53	)
Net expense		$	(4	)	$	(69	)	$	(4	)	$	(213	)

Second Quarter 2006 vs. 2005

In 2006 and 2005, we reported net expenses of $4 million and $69 million, respectively, in our Corporate segment. The net expenses in 2006 reflect a $7 million ($4 million after-tax) charge resulting from the write-off of certain assets no longer in use at one of our electric generating facilities, attributable to our Generation segment. In 2005, the net expenses primarily reflect $67 million of losses incurred in 2005 related to the discontinued operations of VPEM.

Year-To-Date 2006 vs. 2005

In 2006 and 2005, we reported net expenses of $4 million and $213 million, respectively, in our Corporate segment. The net expenses in 2006 reflect a $7 million ($4 million after-tax) charge resulting from the write-off of certain assets no longer in use at one of our electric generating facilities, attributable to our Generation segment. In 2005, the net expenses included $160 million of losses incurred in 2005 related to the discontinued operations of VPEM, as well as the following items attributable to our Generation segment:

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·	A $77 million ($47 million after-tax) charge resulting from the termination of a long-term power purchase agreement; and

·	A $13 million ($8 million after-tax) charge related to our interest in a long-term power tolling contract that was divested in 2005.

Sources and Uses of Cash

We depend 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 provided by 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.

Operating Cash Flows

As presented on our Consolidated Statements of Cash Flows, net cash flows provided by operating activities were $674 million and $617 million during the six months ended June 30, 2006 and 2005, respectively. We believe that our operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and provide dividends to Dominion.

Our operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows. See discussion of such factors in Operating Cash Flows in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2005.

Credit Risk

Our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Presented below is a summary of our gross exposure as of June 30, 2006 for these activities. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. We held no collateral for these transactions at June 30, 2006.

		Gross Credit Exposure
(millions)
Investment grade(1)		$	9
Non-investment grade			—
No external ratings:
Internally rated—investment grade(2)			68
Internally rated—non-investment grade			—
Total		$	77

(1)

Designations as investment grade are based on minimum credit ratings assigned by Moody’s Investors Service (Moody’s) and Standard & Poor’s Ratings Services (Standard & Poor’s). The five largest counterparty exposures, combined, for this category represented approximately 12% of the total gross credit exposure.

(2)	The five largest counterparty exposures, combined, for this category represented approximately 88% of the total gross credit exposure.

Investing Cash Flows

During the six months ended June 30, 2006 and 2005, investing activities resulted in net cash outflows of $470 million and $387 million, respectively. Significant investing activities in the six months ended June 30, 2006 included:

·	$421 million for environmental upgrades, routine capital improvements of generation facilities and construction and improvements of electric transmission and distribution assets;

·	$267 million for purchases of securities held as investments in our nuclear decommissioning trusts; and

·	$60 million for nuclear fuel expenditures; partially offset by

·	$256 million of proceeds from sales of securities held as investments in our nuclear decommissioning trusts; and

·	$20 million of proceeds from the sale of emissions allowances.

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Financing Cash Flows and Liquidity

We rely on banks and capital markets as significant sources of funding for capital requirements not satisfied by the cash provided by our operations. As discussed in Credit Ratings and Debt Covenants, our ability to borrow funds or issue securities and the return demanded by investors are affected by our credit ratings. In addition, the raising of external capital is subject to meeting certain regulatory requirements, including obtaining regulatory approval from the Virginia State Corporation Commission (Virginia Commission).

As presented on our Consolidated Statements of Cash Flows, net cash flows used in financing activities were $238 million and $216 million, respectively, for the six months ended June 30, 2006 and 2005.

See Note 9 to our Consolidated Financial Statements for further information regarding our credit facilities, liquidity and significant financing transactions. Also see Note 12 to our Consolidated Financial Statements for further information regarding our borrowings from Dominion.

Credit Ratings and Debt Covenants

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In Credit Ratings and Debt Covenants of MD&A in our Annual Report on Form 10-K for the year ended December 31, 2005, we discussed our use of capital markets and the impact of credit ratings on the accessibility and costs of using these markets, as well as various covenants present in the enabling agreements underlying our debt. As of June 30, 2006, there have been no changes to or events of default under our debt covenants. As of June 30, 2006, there have been no changes in our credit ratings other than the matters discussed in MD&A in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2006.

Cash Flows from Discontinued Operations

The impact of VPEM’s operations on our 2005 Consolidated Statement of Cash Flows is presented below. We do not expect the transfer of VPEM to Dominion to have a negative impact on our future liquidity.

		Year-To-Date
		2005
(millions)
Operating cash flows		$	35
Investing cash flows			110
Financing cash flows			(145	)

Future Cash Payments for Contractual Obligations

As of June 30, 2006, there have been no material changes outside the ordinary course of business to the contractual obligations disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2005.

Future Issues and Other Matters

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 our Consolidated Financial Statements. This section should be read in conjunction with Future Issues and Other Matters in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2005 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2006.

Virginia Fuel Factor

In May 2006, the Governor of Virginia signed into law Senate Bill 262, a substitute energy bill with a provision that changes the way our Virginia jurisdictional fuel factor is set during the three and one-half year period beginning July 1, 2007. The bill became law effective July 1, 2006.

The fuel factor amendment:

·	Allows annual fuel rate adjustments for three twelve-month periods beginning July 1, 2007 and one six-month period beginning July 1, 2010 (unless capped rates are terminated earlier under the Virginia Restructuring Act);

·	Allows an adjustment at the end of each of the twelve-month periods to account for differences between projections and actual recovery of fuel costs during the prior twelve months; and

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·	Authorizes the Virginia Commission to defer up to 40% of any fuel factor increase approved for the first twelve-month period, with recovery of the deferred amount over the two and one-half year period beginning July 1, 2008 (under prior law, such a deferral was not possible).

The amendment does not allow us to collect any unrecovered fuel expenses incurred prior to July 1, 2007.

PJM Rate Design

In May 2005, the Federal Energy Regulatory Commission (FERC) issued an order finding that PJM's existing transmission service rate design may not be just and reasonable, and ordered an investigation and hearings into the matter. Hearings were held in April 2006, and in July 2006, the Presiding Administrative Law Judge issued an Initial Decision. The Initial Decision concluded that the existing PJM transmission service rate design has been shown to be unjust and unreasonable, and should be replaced with a new rate design effective April 2006. To avoid sudden rate increases, under the Initial Decision, the new rate design would be phased-in so that no customer receives greater than a 10% annual rate increase. The Initial Decision also concluded that other rate designs proposed in the hearing could be considered by FERC as alternatives to the new rate design recommended in the Initial Decision. Our position is that the existing rate design remains just and reasonable, as supported by a broad coalition of PJM stakeholders. After submission of briefs by the parties, FERC will review the Initial Decision and make a determination whether to agree with it or to overrule the decision and issue a different ruling. At this time, we are unable to predict the ruling by FERC; however, we continue to monitor this matter.

Transmission Expansion Plan

In June 2006, PJM, as part of its latest Regional Transmission Expansion Plan, authorized construction of numerous electric transmission upgrades through 2011. We are involved in two of the major construction projects. The first project is an approximately 240-mile 500-kilovolt transmission line from southwestern Pennsylvania to Virginia, of which we will construct approximately 30 miles in Virginia and a subsidiary of Allegheny Energy, Inc. (Allegheny) will construct the remainder. The second project is an approximately 56-mile 500-kilovolt transmission line that we will construct in southeastern Virginia. These transmission upgrades are designed to improve the reliability of the PJM transmission system, including service to our customers. Construction of these transmission lines will be subject to applicable state and federal permits and approvals.

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