ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

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	Three Months Ended September 30,		Nine Months Ended September 30,
	2006	2005	2006	2005
(millions)
Operating Revenue	$1,690	$1,774	$4,346	$4,417
Operating Expenses
Electric fuel and energy purchases	821	964	1,933	1,943
Purchased electric capacity	114	113	340	355
Other energy-related commodity purchases	15	7	33	27
Other operations and maintenance:
External suppliers	110	120	506	520
Affiliated suppliers	75	71	233	215
Depreciation and amortization	133	133	400	396
Other taxes	37	38	125	131
Total operating expenses	1,305	1,446	3,570	3,587
Income from operations	385	328	776	830
Other income	20	24	61	53
Interest and related charges:
Interest expense	65	62	198	197
Interest expense—junior subordinated notes payable to affiliated trust	8	8	23	23
Total interest and related charges	73	70	221	220
Income from continuing operations before income tax expense	332	282	616	663
Income tax expense	123	105	224	247
Income from continuing operations	209	177	392	416
Loss from discontinued operations (net of income tax benefit of $217 and $306    in 2005)	—	(360)	—	(520)
Net Income (Loss)	209	(183)	392	(104)
Preferred dividends	4	4	12	12
Balance available for common stock	$   205	$   (187)	$   380	$   (116)

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

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CONSOLIDATED BALANCE SHEETS

(Unaudited)

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	September 30, 2006	December 31, 2005(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$      23	$       54
Customer accounts receivable (less allowance for doubtful accounts of $7 at    both dates)	738	700
Other receivables (less allowance for doubtful accounts of $10 and $9)	28	67
Inventories	492	443
Other	102	102
Total current assets	1,383	1,366
Investments
Nuclear decommissioning trust funds	1,239	1,166
Other	22	22
Total investments	1,261	1,188
Property, Plant and Equipment
Property, plant and equipment	20,624	20,317
Accumulated depreciation and amortization	(8,362)	(8,055)
Total property, plant and equipment, net	12,262	12,262
Deferred Charges and Other Assets
Intangible assets	158	161
Regulatory assets	268	326
Other	45	146
Total deferred charges and other assets	471	633
Total assets	$15,377	$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) 

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	September 30, 2006	December 31, 2005(1)
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$    1,252	$     618
Short-term debt	—	905
Accounts payable	373	415
Payables to affiliates	39	42
Affiliated current borrowings	352	12
Accrued interest, payroll and taxes	495	288
Other	208	212
Total current liabilities	2,719	2,492
Long-Term Debt
Long-term debt	3,009	3,256
Junior subordinated notes payable to affiliated trust	412	412
Notes payable—other affiliates	220	220
Total long-term debt	3,641	3,888
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	2,242	2,250
Asset retirement obligations	632	834
Regulatory liabilities	420	409
Other	105	86
Total deferred credits and other liabilities	3,399	3,579
Total liabilities	9,759	9,959
Commitments and Contingencies (see Note 11)
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	950	842
Accumulated other comprehensive income	136	117
Total common shareholder's equity	5,361	5,233
Total liabilities and shareholder's equity	$15,377	$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)

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	Nine Months Ended                      September 30,
	2006	2005
(millions)
Operating Activities
Net income (loss)	$    392	$    (104)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net realized and unrealized derivative (gains)/losses	(4)	886
Depreciation and amortization	464	452
Deferred income taxes and investment tax credits, net	(23)	(228)
Deferred fuel expenses, net	73	46
Gain on sale of emissions allowances	(65)	(54)
Other adjustments to net income	(10)	(14)
Changes in:
Accounts receivable	(5)	(78)
Affiliated accounts receivable and payable	—	(24)
Inventories	(49)	(42)
Prepaid pension cost	35	43
Accounts payable	(21)	90
Accrued interest, payroll and taxes	207	92
Other operating assets and liabilities	112	(144)
Net cash provided by operating activities	1,106	921
Investing Activities
Plant construction and other property additions	(631)	(513)
Purchases of nuclear fuel	(92)	(92)
Purchases of securities	(376)	(243)
Proceeds from sales of securities	358	203
Proceeds from sale of emissions allowances	65	56
Other	12	43
Net cash used in investing activities	(664)	(546)
Financing Activities
Repayment of short-term debt, net	(905)	(72)
Issuance of affiliated current borrowings, net	340	201
Issuance of long-term debt	1,000	—
Repayment of long-term debt	(613)	(14)
Common dividend payments	(273)	(453)
Preferred dividend payments	(12)	(12)
Other	(10)	(6)
Net cash used in financing activities	(473)	(356)
Increase (decrease) in cash and cash equivalents	(31)	19
Cash and cash equivalents at beginning of period	54	2
Cash and cash equivalents at end of period	$     23	$     21
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
Conversion of short-term borrowings to contributed capital	—	200

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

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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. As of September 30, 2006, 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 Reports on Forms 10-Q for the quarters ended March 31, 2006 and June 30, 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 September 30, 2006, our results of operations for the three and nine months ended September 30, 2006 and 2005, and our cash flows for the nine months ended September 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

SAB 108

In September 2006, the SEC issued Staff Accounting Bulletin (SAB) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether the current year’s financial statements are materially misstated. The provisions of SAB No. 108 are required to be applied beginning December 31, 2006. We do not expect the adoption of SAB No. 108 to impact our Consolidated Financial Statements.

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.

SFAS No. 157

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

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Note 4.   Operating Revenue

Our operating revenue consists of the following:

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	Three Months Ended    September 30,		Nine Months Ended September 30,
	2006	2005	2006	2005
(millions)
Regulated electric sales	$1,650	$1,729	$4,231	$4,296
Other	40	45	115	121
Total operating revenue	$1,690	$1,774	$4,346	$4,417

Note 5.   Comprehensive Income

The following table presents total comprehensive income:

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	Three Months Ended September 30,		Nine Months Ended September 30,
	2006	2005	2006	2005
(millions)
Net income (loss)	$ 209	$ (183)	$ 392	$ (104)
Other comprehensive income (loss):
Net other comprehensive income (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	4	(2)	(3)	(17)
Other(1)	29	8	22	—
Other comprehensive income (loss)	33	6	19	(17)
Total comprehensive income (loss)	$ 242	$ (177)	$ 411	$ (121)

(1) Primarily represents unrealized gains 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 SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.

The portion of gains on hedging instruments determined to be ineffective and included in net income for the three and nine months ended September 30, 2006 and 2005 were not material. In addition, gains and losses on hedging instruments that were excluded from the measurement of ineffectiveness and included in net income for the three and nine months ended September 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 September 30, 2006:

 

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	AOCI After-Tax	Portion Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	Maximum Term
(millions)
Interest rate	$  1	$—	109 months
Foreign currency	16	7	14 months
Total	$17	$  7

 

 

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.

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 nine months ended September 30, 2005 have been adjusted to reflect VPEM as a discontinued operation, on a net basis. In the three and nine months ended September 30, 2005, our discontinued operations included operating revenue of $151 million and $580 million, respectively, and a loss before income taxes of $577 million and $826 million, respectively.

VPEM’s 2005 results included the following affiliated transactions:

 

 

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	Three Months Ended	Nine Months Ended
	September 30, 2005
(millions)
Purchases of natural gas, gas transportation and storage services from affiliates	$284	$771
Sales of natural gas to affiliates	450	948
Net realized losses on affiliated commodity derivative contracts	31	18
Affiliated interest and related charges	6	13

Note 8.   Asset Retirement Obligations

The following table describes the changes to our asset retirement obligations during the nine months ended September 30, 2006:

 

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	Amount
(millions)
Asset retirement obligations at December 31, 2005	$834
Accretion expense	32
Revisions in estimated cash flows(1)	(234)
Asset retirement obligations at September 30, 2006	$632

(1)	Primarily reflects a reduction in cost escalation rate assumptions that were applied to updated decommissioning cost studies received for each of our nuclear facilities during the third quarter of 2006.

Note 9.   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), had 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).

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In September 2006, we received sufficient information from one of the potential VIEs and performed our FIN 46R analysis. As a result of the analysis, we determined that the entity is not a VIE. As of September 30, 2006, the requested information has not been received from the two 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 two potential VIE supplier entities of $1.3 billion at September 30, 2006. We are not subject to any risk of loss from these potential VIEs, other than the remaining purchase commitments. We paid $24 million and $25 million for electric generation capacity and $31 million and $45 million for electric energy to these entities in the three months ended September 30, 2006 and 2005, respectively. We paid $72 million and $81 million for electric generation capacity and $68 million and $79 million for electric energy to these entities in the nine months ended September 30, 2006 and 2005, respectively.

During 2005, we entered into four long-term contracts with unrelated limited liability corporations (LLCs) to purchase coal and 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 $36 million and $67 million to the LLCs for coal and synthetic fuel produced from coal in the three months ended September 30, 2006 and 2005, respectively, and $243 million and $130 million to the LLCs for coal and synthetic fuel produced from coal in the nine months ended September 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 September 30, 2006 and December 31, 2005 reflect net property, plant and equipment of $340 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 10.   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 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 September 30, 2006, total outstanding commercial paper supported by the joint credit facility was $165 million, none of which were our borrowings. At September 30, 2006, total outstanding letters of credit supported by the joint credit facility were $302 million, of which less than $1 million was issued on our behalf.

At September 30, 2006, capacity available under the credit facility was $2.5 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 nine months ended September 30, 2006, we repaid $613 million of our long-term debt.

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Note 11.   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 Notes 9 and 10 to the Consolidated Financial Statements in our Quarterly Reports on Forms 10-Q for the quarters ended March 31, 2006 and June 30, 2006, respectively, nor have any significant new matters arisen during the quarter ended September 30, 2006.

Litigation

As discussed in Note 21 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005, we are co-owners with Old Dominion Electric Cooperative (ODEC) of the Clover electric generating facility. In 1989, we entered into a coal transportation agreement with Norfolk Southern Railway Company (Norfolk Southern) for the delivery of coal to the facility. The agreement provided for a base rate price adjustment based upon a published index. Norfolk Southern claimed in October 2003 that an incorrect reference index was used to adjust the base transportation rate. In November 2003, we and ODEC filed suit against Norfolk Southern seeking to clarify the price escalation provisions of the transportation agreement. The trial court has ruled in Norfolk Southern’s favor by concluding that the agreement specifies the higher rate adjustment factor which Norfolk Southern claims should have been applied in the past to adjust the base rate and which will be applied in the future. On September 1, 2006, the court entered an order directing us and ODEC to correct invoices from December 1, 2003 to the present by calculating rates under the higher rate adjustment factor as if it had been applied from the inception of the agreement, to tender the difference to Norfolk Southern with interest at the rate provided by the agreement and to calculate future invoices using the higher rate adjustment factor as if it had been applied from the inception of the agreement. The cumulative amount of the adjustment as of the time the court entered its order was approximately $50 million plus interest, of which our share would be one half. We and ODEC have filed a notice of appeal to the Virginia Supreme Court and have posted security to suspend execution of the judgment during the appeal. We believe the court’s interpretation of the transportation agreement and its ruling on other issues in the case are legally incorrect. No liability has been recorded in our Consolidated Financial Statements related to this matter.

Guarantees and Surety Bonds

As of September 30, 2006, we had issued less than $2 million of guarantees primarily to support commodity transactions of our subsidiaries. We had also purchased $66 million of surety bonds for various purposes, including the posting of security to suspend execution of the judgement during the appeal of the Norfolk Southern matter, as discussed in the Litigation section above, and providing workers’ compensation coverage. Under the terms of surety bonds, we are obligated to indemnify the respective surety bond company for any amounts paid.

Note 12.   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 September 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 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 September 30, 2006, our gross credit exposure totaled $71 million. Of this amount, 93% related to a single counterparty; however, the entire balance is with investment grade entities. We held no collateral for these transactions at September 30, 2006.

Note 13.   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.

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Transactions with Affiliates

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

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

 

 

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	Three Months Ended September 30,		Nine Months Ended September 30,
	2006	2005	2006	2005
(millions)
Commodity purchases from affiliates	$132	$191	$212	$312
Services provided by affiliates	75	71	233	215
Services provided to affiliates	7	12	19	24

Transactions with Dominion

We have borrowed funds from Dominion under both short-term and long-term borrowing arrangements. At September 30, 2006 and December 31, 2005, our outstanding borrowings, net of repayments, under the Dominion money pool for our nonregulated subsidiaries totaled $178 million and $12 million, respectively. Our short-term demand note borrowings were $175 million at September 30, 2006. There were no short-term demand note borrowings at December 31, 2005. At September 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 $4 million and $2 million in the three months ended September 30, 2006 and 2005, respectively, and $7 million and $5 million in the nine months ended September 30, 2006 and 2005, respectively.

Note 14.   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:

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, power purchase agreements 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 nine months ended September 30, 2006 and 2005, we reported net expenses of $4 million and $573 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 $520 million of losses incurred in the nine months ended September 30, 2005 relating 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.

The following table presents segment information pertaining to our operations: 

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	Delivery	Energy	Generation	Corporate	Consolidated Total
(millions)
Three Months Ended September 30, 2006
Operating revenue	$324	$57	$1,307	$2	$1,690
Net income	79	21	109	—	209
Three Months Ended September 30, 2005
Operating revenue	$332	$61	$1,380	$1	$1,774
Loss from discontinued operations, net of tax	—	—	—	(360)	(360)
Net income (loss)	97	25	55	(360)	(183)
Nine Months Ended September 30, 2006
Operating revenue	$900	$161	$3,283	$2	$4,346
Net income (loss)	212	54	130	(4)	392
Nine Months Ended September 30, 2005
Operating revenue	$903	$163	$3,345	$6	$4,417
Loss from discontinued operations, net of tax	—	—	—	(520)	(520)
Net income (loss)	238	53	178	(573)	(104)

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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 Reports on Forms 10-Q for the quarters ended March 31, 2006 and June 30, 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 September 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 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.

SFAS No. 157

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

Results of Operations

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

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	Third Quarter			Year-To-Date
	2006	2005	$ Change	2006	2005	$ Change
(millions)
Net income (loss)	$209	$(183)	$392	$392	$(104)	$496

Overview

Third Quarter 2006 vs. 2005

Net income increased by $392 million to $209 million. Favorable drivers include the absence of $360 million of after-tax losses incurred in 2005 by the discontinued operations of VPEM; a decrease in unrecovered Virginia fuel expenses due to lower commodity prices, including purchased power and decreased consumption of fossil fuel; and an increase in gains recognized from the sale of emissions allowances. Unfavorable drivers include a decrease in regulated electric sales revenue resulting from milder weather and other factors and major storm damage and service restoration costs associated with tropical storm Ernesto in September 2006.

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Year-To-Date 2006 vs. 2005

Net income increased by $496 million to $392 million. Favorable drivers include the absence of $520 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 a decrease in regulated electric sales revenue resulting from milder weather and other factors and major storm damage and service restoration costs associated with tropical storm Ernesto in September 2006.

Analysis of Consolidated Operations

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

 

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	Third Quarter			Year-To-Date
	2006	2005	$ Change	2006	2005	$ Change
(millions)
Operating Revenue	$1,690	$1,774	$(84)	$4,346	$4,417	$(71)
Operating Expenses
Electric fuel and energy purchases	821	964	(143)	1,933	1,943	(10)
Purchased electric capacity	114	113	1	340	355	(15)
Other energy-related commodity purchases	15	7	8	33	27	6
Other operations and maintenance	185	191	(6)	739	735	4
Depreciation and amortization	133	133	—	400	396	4
Other taxes	37	38	(1)	125	131	(6)
Other income	20	24	(4)	61	53	8
Interest and related charges	73	70	3	221	220	1
Income tax expense	123	105	18	224	247	(23)
Loss from discontinued operations, net of tax	—	(360)	360	—	(520)	520

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

Third Quarter 2006 vs. 2005

Operating Revenue decreased 5% to $1.7 billion, reflecting the combined effects of:

·	A $76 million decrease associated with milder weather. As compared to the prior year, we experienced a 13% decline in cooling degree days; and

·	A $55 million decrease in sales to wholesale customers primarily resulting from milder weather; partially offset by

·	A $25 million increase due to new customer connections primarily in our residential and commercial customer classes;

·	A $12 million increase attributable to variations in rates resulting from changes in customer usage patterns and sales mix and other factors;

·	A $7 million increase in nonutility coal sales, primarily reflecting higher volumes; and

·	A $6 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.

Operating Expenses and Other Items

Electric fuel and energy purchases expense decreased 15% to $821 million, primarily due to lower commodity prices, including purchased power, and decreased consumption of fossil fuel as a result of milder weather.

Other energy-related commodity purchases expense increased 114% to $15 million, reflecting an increase in nonutility coal purchased for resale, as discussed in Operating Revenue.

Other operations and maintenance expense decreased 3% to $185 million, primarily reflecting:

· A $44 million increase in gains from the sale of emissions allowances; partially offset by

· An $18 million increase related to major storm damage and service restoration costs associated with our distribution operations primarily resulting from tropical storm Ernesto in September 2006; and

· A $15 million increase due to a reduced benefit from 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.

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Other income decreased 17% to $20 million, primarily reflecting a $3 million decrease 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.

Year-To-Date 2006 vs. 2005

Operating Revenue decreased 2% to $4.3 billion, reflecting the combined effects of:

· A $158 million decrease associated with milder weather. As compared to the prior year, we experienced an 8% decline in cooling degree days and a 17% decline in heating degree days; and

· A $41 million decrease in sales to wholesale customers primarily resulting from milder weather; partially offset by

· A $64 million increase due to new customer connections primarily in our residential and commercial customer classes;

· A $31 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;

· A $28 million increase attributable to rate variations resulting from changes in customer usage patterns and sales mix and other factors;

· A $10 million increase due to the collection of a new Virginia sales and use tax surcharge from customers; and

· A $5 million increase in nonutility coal sales, primarily reflecting higher volumes ($9 million), partially offset by decreased sales prices ($4 million).

Operating Expenses and Other Items

Purchased electric capacity expense decreased 4% to $340 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 energy-related commodity purchases expense increased 22% to $33 million, reflecting an increase in nonutility coal purchased for resale, as discussed in Operating Revenue.

Other operations and maintenance expense increased 1% to $739 million, primarily reflecting:

· A $23 million increase related to major storm damage and service restoration costs associated with our distribution operations, primarily resulting from tropical storm Ernesto in September 2006;

· A $19 million increase in outage costs primarily due to an increase in the number of scheduled outages at certain of our electric generating facilities;

· A $14 million increase resulting from higher salaries, wages, and pension and medical benefits;

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

· A $6 million increase due to the amortization of a regulatory asset associated with amounts subject to collection under a Virginia sales and use tax surcharge, net of credits resulting from additions to the regulatory asset during the period; partially offset by

· A $17 million benefit related to 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;

· An $11 million increase in gains from the sale of emissions allowances; 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 15% to $61 million, primarily reflecting an $8 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.

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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 September 30, 2006 and 2005:

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	Third Quarter			Year-To-Date
	2006	2005	$ Change	2006	2005	$ Change
(millions)
Delivery	$ 79	$ 97	$(18)	$ 212	$ 238	$(26)
Energy	21	25	(4)	54	53	1
Generation	109	55	54	130	178	(48)
Primary operating segments	209	177	32	396	469	(73)
Corporate	—	(360)	360	(4)	(573)	569
Consolidated	$ 209	$(183)	$392	$ 392	$(104)	$496

Delivery

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

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	Third Quarter			Year-To-Date
	2006	2005	% Change	2006	2005	% Change
Electricity delivered (million mwhrs)	23.1	23.8	(3)%	61.2	62.3	(2)%
Degree days (electric service area):
Cooling(1)	1,119	1,282	(13)	1,528	1,652	(8)
Heating(2)	15	2	650	2,056	2,468	(17)
Average electric delivery customer accounts(3)	2,330	2,289	2	2,322	2,280	2

mwhrs = megawatt hours

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

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

(3) In thousands.

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

 

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	Third Quarter	Year-To-Date
	2006 vs. 2005	2006 vs. 2005
	Increase (Decrease)	Increase (Decrease)
(millions)
Major storm damage and service restoration(1)	$(11)	$(14)
Regulated electric sales:
Weather	(9)	(21)
Customer growth	3	9
2005 North Carolina rate case settlement	—	(6)
Other	(1)	6
Change in net income contribution	$(18)	$(26)

(1) Principally resulting from costs associated with tropical storm Ernesto in September 2006.

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Energy

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

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	Third 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)	(4)
Customer growth	1	2
Other	(3)	(1)
Change in net income contribution	$  (4)	$  1

(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.

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:

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	Third Quarter			Year-To-Date
	2006	2005	% Change	2006		2005		% Change
Electricity supplied (million mwhrs)	23.0	23.8	(3)%	61.2	62.3		(2)%
Degree days (electric service area):
Cooling	1,119	1,282	(13)	1,528	1,652		(8)
Heating	15	2	650	2,056	2,468		(17)

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

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	Third Quarter	Year-To-Date
	2006 vs. 2005	2006 vs. 2005
	Increase (Decrease)	Increase (Decrease)
(millions)
Unrecovered Virginia fuel expenses(1)	$60	$9
Sale of emissions allowances	27	7
Outage costs	3	(12)
Energy supply margin(2)	(15)	(17)
Regulated electric sales:
Weather	(24)	(48)
Customer growth	8	19
2005 North Carolina rate case settlement	—	(10)
Other	(5)	4
Change in net income contribution	$54	$(48)

(1) Reflects lower commodity prices and decreased consumption of fossil fuel due to milder weather.

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

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Corporate

Corporate includes our corporate and other functions, as well as the discontinued operations of VPEM. In addition, the contribution to net income by our primary operating segments is determined based on a measure of profit that executive management believes represents 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. Presented below are the Corporate segment’s after-tax results. 

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	Third Quarter			Year-To-Date
	2006	2005	$ Change	2006	2005	$ Change
(millions)
VPEM discontinued operations	$—	$(360)	$360	$—	$(520)	$520
Specific items attributable to operating segments	—	—	—	(4)	(53)	49
Net expense	$—	$(360)	$360	$(4)	$(573)	$569

Third Quarter 2006 vs. 2005

In 2005, we reported net expenses of $360 million in our Corporate segment due to losses 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 $573 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 $520 million of losses related 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.

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 $1.1 billion and $921 million for the nine months ended September 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 September 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 September 30, 2006.

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	Gross Credit Exposure
(millions)
Investment grade(1)	$ 4
Non-investment grade	—
No external ratings:
Internally rated—investment grade(2)	67
Internally rated—non-investment grade	—
Total	$71

(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 6% of the total gross credit exposure.

(2) The five largest counterparty exposures, combined, for this category represented approximately 94% of the total gross credit exposure.

Investing Cash Flows

For the nine months ended September 30, 2006 and 2005, investing activities resulted in net cash outflows of $664 million and $546 million, respectively. Significant investing activities in the nine months ended September 30, 2006 included:

· $631 million for environmental upgrades, routine capital improvements of generation facilities and construction and improvements of electric transmission and distribution assets;

· $376 million for purchases of securities held as investments in our nuclear decommissioning trusts; and

· $92 million for nuclear fuel expenditures; partially offset by

· $358 million of proceeds from sales of securities held as investments in our nuclear decommissioning trusts; and

· $65 million of proceeds from the sale of emissions allowances.

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 $473 million and $356 million, respectively, for the nine months ended September 30, 2006 and 2005.

See Note 10 to our Consolidated Financial Statements for further information regarding our credit facilities, liquidity and significant financing transactions. Also see Note 13 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 September 30, 2006, there have been no changes to or events of default under our debt covenants. As of September 30, 2006, there have been no changes in our credit ratings other than the matters discussed in MD&A in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006.

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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.

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	Year-To-Date
	2005
(millions)
Operating cash flows	$107
Investing cash flows	110
Financing cash flows	(216)

Future Cash Payments for Contractual Obligations

As of September 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 Reports on Forms 10-Q for the quarters ended March 31, 2006 and June 30, 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 Electric Utility 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

· 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.

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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 our future.

Market Risk Sensitive Instruments and Risk Management

Our financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates, foreign currency exchange rates and equity security prices as described below. Commodity price risk is due to our exposure to market shifts for prices received and paid for natural gas, electricity and other commodities. Interest rate risk is generally related to our outstanding debt. We are exposed to foreign currency exchange rate risks related to our purchases of fuel and fuel services denominated in foreign currencies. In addition, we are exposed to equity price risk through various portfolios of equity securities.

The following 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% unfavorable change in commodity prices, interest rates and foreign currency exchange rates.

Commodity Price Risk

To manage price risk, we primarily hold commodity-based financial derivative instruments for nontrading purposes associated with the purchase of electricity and natural gas. As discussed in Note 8 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005, we completed the transfer of VPEM to Dominion on December 31, 2005. As a result, at December 31, 2005, we did not have significant exposure to commodity price risk associated with financial derivative instruments. As part of VPEM’s strategy to market energy and manage related risks prior to its transfer to Dominion on December 31, 2005, it maintained commodity-based financial derivative instruments held for both trading and nontrading purposes.

The derivatives used to manage our commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps and options that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the fair value of commodity-based financial derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on actively quoted market prices.

At September 30, 2006 and December 31, 2005, we did not have significant exposure to commodity price risk associated with financial derivative instruments.

The impact of a change in energy commodity prices on our nontrading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. For example, our expenses for power purchases when combined with the settlement of commodity derivative instruments used for hedging purposes, will generally result in a range of prices for those purchases contemplated by the risk management strategy.

Interest Rate Risk

We manage our interest rate risk exposure predominantly by maintaining a portfolio of fixed and variable rate debt. We also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at September 30, 2006 and December 31, 2005, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $5 million and $6 million, respectively.

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Foreign Currency Exchange Risk

We have foreign currency exchange risk exposure associated with anticipated future purchases of nuclear fuel and nuclear fuel processing services denominated in foreign currencies. We manage certain of these risks by utilizing currency forward contracts. As a result of holding these contracts as hedges, our exposure to foreign currency risk for these purchases is minimal. A hypothetical 10% unfavorable change in relevant foreign exchange rates would have resulted in a decrease of approximately $4 million and $6 million in the fair value of currency forward contracts held by us at September 30, 2006 and December 31, 2005, respectively.

Investment Price Risk

We are subject to investment price risk due to marketable securities held as investments in nuclear decommissioning trust funds. These marketable securities are reported on our Consolidated Balance Sheets at fair value. We recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $33 million and $24 million for the nine months ended September 30, 2006 and 2005, respectively, and $32 million for the year ended December 31, 2005. We recorded, in AOCI, net unrealized gains on decommissioning trust investments of $37 million and net unrealized losses on decommissioning trust investments of $1 million for the nine months ended September 30, 2006 and 2005, respectively, and net unrealized gains on decommissioning trust investments of $10 million for the year ended December 31, 2005.

Dominion sponsors employee pension and other postretirement benefit plans, in which our 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 our recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash that we will contribute to the employee benefit plans.

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