Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark one)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2009

or

 

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File Number 001-02255

 

 

VIRGINIA ELECTRIC AND POWER COMPANY

(Exact name of registrant as specified in its charter)

 

 

 

VIRGINIA		54-0418825
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

 

120 TREDEGAR STREET RICHMOND, VIRGINIA		23219
(Address of principal executive offices)		(Zip Code)

(804) 819-2000

(Registrant’s telephone number)

 

 

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer		¨		Accelerated filer		¨
Non-accelerated filer		x  (Do not check if a smaller reporting company)		Smaller reporting company		¨

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

At September 30, 2009, the latest practicable date for determination, 209,833 shares of common stock, without par value, of the registrant were outstanding.

 

 

 

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VIRGINIA ELECTRIC AND POWER COMPANY

INDEX

 

				Page Number
		Glossary of Terms		3
PART I. Financial Information
Item 1.		Financial Statements
		Consolidated Statements of Income – Three and Nine Months Ended September 30, 2009 and 2008		4
		Consolidated Balance Sheets – September 30, 2009 and December 31, 2008		5
		Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2009 and 2008		7
		Notes to Consolidated Financial Statements		8
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 3.		Quantitative and Qualitative Disclosures About Market Risk		31
Item 4.		Controls and Procedures		32
PART II. Other Information
Item 1.		Legal Proceedings		33
Item 1A.		Risk Factors		33
Item 6.		Exhibits		34

 

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GLOSSARY OF TERMS

The following abbreviations or acronyms used in this Form 10-Q are defined below:

 

Abbreviation or Acronym		Definition
Affiliates		Other Dominion subsidiaries
AFUDC		Allowance for funds used during construction
AOCI		Accumulated other comprehensive income (loss)
AROs		Asset retirement obligations
bcf		Billion cubic feet
CEO		Chief Executive Officer
CFO		Chief Financial Officer
Dominion		Dominion Resources, Inc.
DRS		Dominion Resources Services, Inc., a subsidiary of Dominion
DVP		Dominion Virginia Power operating segment
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FTRs		Financial transmission rights
GAAP		U.S. generally accepted accounting principles
kWh		Kilowatt-hour
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
Moody’s		Moody’s Investors Service
MW		Megawatt
MWh		Megawatt-hour
North Anna		North Anna power station
PJM		PJM Interconnection, LLC
ROE		Return on equity
RTO		Regional transmission organization
SEC		Securities and Exchange Commission
Standard & Poor’s		Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
U.S.		United States of America
VIEs		Variable interest entities
Virginia City Hybrid Energy Center		A 585 Mw (nominal) carbon-capture compatible, clean-coal powered electric generation facility currently under construction in Wise County, Virginia
Virginia Commission		Virginia State Corporation Commission

 

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VIRGINIA ELECTRIC AND POWER COMPANY

PART I. FINANCIAL INFORMATION

 

ITEM 1.

FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2009			2008			2009			2008
(millions)
Operating Revenue		$	1,938		$	2,177		$	5,472		$	5,247
Operating Expenses
Electric fuel and other energy-related purchases			740			974			2,219			1,971
Purchased electric capacity			95			102			307			305
Other operations and maintenance:
Affiliated suppliers			109			98			310			274
Other			230			242			757			735
Depreciation and amortization			162			154			479			453
Other taxes			48			46			145			140
Total operating expenses			1,384			1,616			4,217			3,878
Income from operations			554			561			1,255			1,369
Other income			33			6			65			24
Interest and related charges(1)			89			82			263			239
Income before income tax expense			498			485			1,057			1,154
Income tax expense			183			182			389			429
Net Income			315			303			668			725
Preferred dividends			4			4			12			12
Balance available for common stock		$	311		$	299		$	656		$	713

 

(1)	Includes $12 million incurred with an affiliated trust for the nine months ended September 30, 2008.

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

 

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

		September 30, 2009				December 31, 2008(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents		$	23			$	27
Customer accounts receivable (less allowance for doubtful accounts of $12 and $8)			938				940
Other receivables (less allowance for doubtful accounts of $5 and $7)			52				82
Inventories (average cost method)			602				547
Prepayments			67				28
Regulatory assets			394				212
Other			82				75
Total current assets			2,158				1,911
Investments
Nuclear decommissioning trust funds			1,180				1,053
Other			3				3
Total investments			1,183				1,056
Property, Plant and Equipment
Property, plant and equipment			25,046				23,476
Accumulated depreciation and amortization			(9,283	)			(8,915	)
Total property, plant and equipment, net			15,763				14,561
Deferred Charges and Other Assets
Regulatory assets			275				921
Other			298				353
Total deferred charges and other assets			573				1,274
Total assets		$	19,677			$	18,802

 

(1)	Our Consolidated Balance Sheet at December 31, 2008 has been derived from the audited Consolidated Financial Statements at that date.

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

 

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

 

		September 30, 2009			December 31, 2008(1)
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year		$	15		$	125
Short-term debt			—			297
Accounts payable			343			436
Payables to affiliates			63			132
Affiliated current borrowings			1,062			417
Accrued interest, payroll and taxes			283			236
Other			427			386
Total current liabilities			2,193			2,029
Long-Term Debt			6,449			6,000
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits			2,339			2,485
Asset retirement obligations			626			715
Regulatory liabilities			935			760
Other			295			282
Total deferred credits and other liabilities			4,195			4,242
Total liabilities			12,837			12,271
Commitments and Contingencies (see Note 13)
Preferred Stock Not Subject to Mandatory Redemption			257			257
Common Shareholder’s Equity
Common stock—no par, 300,000 shares authorized; 209,833 shares outstanding			3,738			3,738
Other paid-in capital			1,110			1,110
Retained earnings			1,714			1,421
Accumulated other comprehensive income			21			5
Total common shareholder’s equity			6,583			6,274
Total liabilities and shareholder’s equity		$	19,677		$	18,802

 

(1)	Our Consolidated Balance Sheet at December 31, 2008 has been derived from the audited Consolidated Financial Statements at that date.

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

 

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		Nine Months Ended September 30,
		2009				2008
(millions)
Operating Activities
Net income		$	668			$	725
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			556				524
Deferred income taxes and investment tax credits			(103	)			305
Other adjustments			(44	)			(37	)
Changes in:
Accounts receivable			24				(173	)
Affiliated accounts receivable and payable			(15	)			61
Inventories			(55	)			(38	)
Deferred fuel expenses			514				(514	)
Accounts payable			(49	)			(84	)
Accrued interest, payroll and taxes			47				66
Prepayments			(40	)			138
Other operating assets and liabilities			83				(28	)
Net cash provided by operating activities			1,586				945
Investing Activities
Plant construction and other property additions			(1,745	)			(1,330	)
Purchases of nuclear fuel			(90	)			(88	)
Purchases of securities			(624	)			(345	)
Proceeds from sales of securities			607				303
Other			(53	)			84
Net cash used in investing activities			(1,905	)			(1,376	)
Financing Activities
Issuance (repayment) of short-term debt, net			(297	)			407
Issuance of affiliated current borrowings, net			646				226
Repayment of affiliated notes payable			—				(412	)
Issuance of long-term debt			460				630
Repayment of long-term debt			(120	)			(62	)
Common dividend payments			(366	)			(361	)
Preferred dividend payments			(12	)			(12	)
Other			4				(7	)
Net cash provided by financing activities			315				409
Decrease in cash and cash equivalents			(4	)			(22	)
Cash and cash equivalents at beginning of period			27				49
Cash and cash equivalents at end of period		$	23			$	27
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures		$	78			$	3

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

 

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Virginia Electric and Power Company (Virginia Power) is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. We are a member of PJM, a regional transmission organization (RTO), and our electric transmission facilities are integrated into the PJM wholesale electricity markets. All of our common stock is owned by our parent company, Dominion Resources, Inc. (Dominion).

We manage our daily operations through two primary operating segments: Dominion Virginia Power (DVP) and Generation. In addition, we also report a Corporate and Other segment that primarily includes specific items attributable to our operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 16 for further discussion of our operating segments.

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 Power, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power, 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 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 GAAP. These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2008 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009.

In our opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly our financial position as of September 30, 2009, our results of operations for the three and nine months ended September 30, 2009 and 2008, and our cash flows for the nine months ended September 30, 2009 and 2008. Such adjustments are normal and recurring in nature unless otherwise noted.

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.

In accordance with GAAP, we report certain contracts and instruments at fair value. See Note 6 for further information on fair value measurements.

The results of operations for 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 other energy-related purchases and other factors.

Certain amounts in our 2008 Consolidated Financial Statements and Notes have been recast to conform to the 2009 presentation.

We have evaluated subsequent events through November 2, 2009, the date our Consolidated Financial Statements were issued.

 

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Note 3. Newly Adopted Accounting Standards

Recognition and Presentation of Other-Than-Temporary Impairments

The FASB amended its guidance for the recognition and presentation of other-than-temporary impairments, which we adopted effective April 1, 2009. The recognition provisions of this guidance apply only to debt securities classified as available for sale or held to maturity, while the presentation and disclosure requirements apply to both debt and equity securities. Prior to the adoption of this guidance, as described in Note 2 in our Annual Report on Form 10-K for the year ended December 31, 2008, we considered all debt securities held by our nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired as we did not have the ability to ensure the investments were held through the anticipated recovery period.

Effective with the adoption of this guidance, using information obtained from our nuclear decommissioning trust fixed-income investment managers, we record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more likely than not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. For any debt security that is deemed to have experienced a credit loss, we record the credit loss in earnings and any remaining portion of the unrealized loss in other comprehensive income. We evaluate credit losses primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors. For certain jurisdictions subject to cost-based regulation, all net realized and unrealized gains and losses on debt securities (including any other-than-temporary impairments) continue to be recorded to a regulatory liability.

Upon the adoption of this guidance for debt investments held at April 1, 2009, we recorded a $3 million ($2 million after-tax) cumulative effect of a change in accounting principle to reclassify the non-credit related portion of previously recognized other-than-temporary impairments from retained earnings to AOCI, reflecting the fixed-income investment managers’ intent and ability to hold the debt securities until the amortized cost bases are recovered.

Note 4. Income Taxes

In the second quarter of 2009, the U.S. Congressional Joint Committee on Taxation completed its review of our settlement with the Appellate Division of the Internal Revenue Service (IRS Appeals) for tax years 1999 through 2001. We were entitled to a $39 million refund, of which $20 million was applied as an estimated payment for 2009 taxes and $19 million was paid to us in October 2009. Settlement negotiations with IRS Appeals regarding our protest of adjustments proposed for tax years 2002 and 2003 are ongoing. In addition, the Internal Revenue Service (IRS) has completed its audit and has proposed adjustments for tax years 2004 and 2005. We filed protests for certain of those adjustments in July 2009.

At September 30, 2009, unrecognized tax benefits related to current year tax positions were $14 million. During the nine months ended September 30, 2009, unrecognized tax benefits related to prior year uncertain tax positions increased on a gross basis by $11 million and decreased on a gross basis by $66 million. In addition, unrecognized tax benefits for prior years decreased by $7 million for settlements with tax authorities, $7 million for amounts that otherwise become deductible in 2009 and $3 million for expiration of statutes of limitations.

See Note 5 to our Annual Report on Form 10-K for the year ended December 31, 2008, for a discussion of reasonably possible changes that could occur in our unrecognized tax benefits during the next twelve months, including our efforts to eliminate or reduce uncertainty regarding the calculation of our qualified production activities deduction under the IRS Pre-filing Program. It is reasonably possible that we could reach an agreement with the IRS about our calculation in the fourth quarter of 2009, and unrecognized tax benefits for 2009 and prior years would decrease by $10 million to $15 million, which would be reflected in our earnings. In addition, with the completion of the audit of tax years 2004 and 2005, it is reasonably possible that unrecognized tax benefits could decrease up to $28 million over the next twelve months, resulting from successful settlement negotiations or payments to tax authorities, with no material impact on our results of operations.

 

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Note 5. Comprehensive Income

The following table presents total comprehensive income:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009			2008
(millions)
Net income		$	315			$	303			$	668		$	725
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			(2	)			(2	)			6			(1	)
Other, net of tax			5				(4	)			12			(12	)
Other comprehensive income (loss)			3				(6	)			18			(13	)
Total comprehensive income		$	318			$	297			$	686		$	712

Other comprehensive income for the nine months ended September 30, 2009 excludes a $3 million ($2 million after-tax) adjustment to AOCI representing the cumulative effect of the change in accounting principle related to the recognition and presentation of other-than-temporary impairments.

Note 6. Fair Value Measurements

Our fair value measurements are made in accordance with the policies discussed in Note 6 to our Annual Report on Form 10-K for the year ended December 31, 2008. In addition, see Note 7 in this report for further information about our derivatives and hedge accounting activities.

The following table presents our assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

 

		Level 1			Level 2			Level 3			Total
(millions)
As of September 30, 2009
Assets
Derivatives		$	—		$	90		$	2		$	92
Investments:
Marketable equity securities			614			—			—			614
Marketable debt securities:
Corporate bonds			—			158			—			158
U.S. Treasury securities and agency debentures			99			11			—			110
State and municipal			—			181			—			181
Other			—			1			—			1
Cash equivalents and other			—			15			—			15
Total assets		$	713		$	456		$	2		$	1,171
Liabilities
Derivatives		$	—		$	6		$	54		$	60
As of December 31, 2008
Assets
Derivatives		$	—		$	60		$	7		$	67
Investments:
Marketable equity securities			147			321			—			468
Marketable debt securities:
Corporate bonds			—			151			—			151
U.S. Treasury securities and agency debentures			78			48			—			126
State and municipal			—			183			—			183
Cash equivalents and other			—			11			—			11
Total assets		$	225		$	774		$	7		$	1,006
Liabilities
Derivatives		$	—		$	23		$	76		$	99

 

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

The following table presents the net changes in the assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
(millions)
Beginning balance		$	(8	)		$	210			$	(69	)		$	(4	)
Total realized and unrealized gains or (losses):
Included in earnings			(14	)			17				(152	)			106
Included in regulatory assets/liabilities			(45	)			(249	)			10				(49	)
Purchases, issuances and settlements			15				(37	)			157				(112	)
Transfers out of Level 3			—				—				2				—
Ending balance		$	(52	)		$	(59	)		$	(52	)		$	(59	)
The amount of gains (losses) for the period included in earnings attributable to the change in unrealized gains/losses relating to assets still held at the reporting date		$	—			$	(19	)		$	—			$	(4	)

The gains and losses included in earnings in the Level 3 fair value category, including those attributable to the change in unrealized gains and losses relating to assets still held at the reporting date, were classified in electric fuel and other energy-related purchases expense in our Consolidated Statements of Income for the three and nine months ended September 30, 2009 and 2008.

As of September 30, 2009, our net balance of commodity derivatives categorized as Level 3 fair value measurements was a net liability of $52 million. A hypothetical 10% increase in commodity prices would increase the net liability by $2 million, while a hypothetical 10% decrease in commodity prices would decrease the net liability by $2 million.

There were no significant non-financial assets or liabilities that were measured at fair value on a nonrecurring basis during the nine months ended September 30, 2009.

Fair Value of Financial Instruments

Substantially all of our financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of our cash and cash equivalents, customer and other receivables, short-term debt and accounts payable are representative of fair value due to the short-term nature of these instruments. The financial instruments’ carrying amounts and fair values are as follows:

 

		September 30, 2009						December 31, 2008
		Carrying Amount			Estimated Fair Value(1)			Carrying Amount			Estimated Fair Value(1)
(millions)
Long-term debt, including securities due within one year(2)		$	6,464		$	7,211		$	6,125		$	6,231
Preferred stock(3)			257			240			257			231

 

(1)

Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2)

The estimated fair value compared to the carrying amount increased during the current period due to the recovery in corporate credit spreads since December 31, 2008. Also includes net unamortized discount of $4 million and $2 million at September 30, 2009 and December 31, 2008, respectively, and the valuation of certain fair value hedges associated with our fixed rate debt of $1 million at September 30, 2009 and December 31, 2008.

(3)	Includes issuance expenses of $2 million at September 30, 2009 and December 31, 2008.

 

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Note 7. Derivatives and Hedge Accounting Activities

Our accounting policies and objectives and strategies for using derivative instruments are discussed in Note 2 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008.

The following table presents the volume of our derivative activity as of September 30, 2009. These volumes are based on open derivative positions and represent the combined absolute value of our long and short positions, except in the case of offsetting deals, for which we present the absolute value of the net volume of our long and short positions.

 

		Current			Noncurrent
Natural Gas (bcf):
Fixed price			3.2			—
Basis			1.6			—
Electricity (MWh):
Fixed price			252,000			—
FTRs			70,601,527			—
Capacity (MW)			477,366			474,600
Interest rate		$	550,000,000		$	375,000,000
Foreign currency (euros)			13,847,638			—

For the three and nine months ended September 30, 2009 and 2008, gains or losses on hedging instruments determined to be ineffective were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices and were not material for the three and nine months ended September 30, 2009 and 2008.

The following table presents selected information related to gains on cash flow hedges included in AOCI in our Consolidated Balance Sheet at September 30, 2009:

 

		AOCI After-Tax			Portion Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Interest rate		$	6		$	—		371 months
Other			4			2		62 months
Total		$	10		$	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.

 

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of our derivatives as of September 30, 2009 and where they are presented on our Consolidated Balance Sheet:

 

		Fair Value – Derivatives under Hedge Accounting			Fair Value – Derivatives not under Hedge Accounting			Total Fair Value
(millions)
ASSETS
Current Assets
Commodity		$	19		$	2		$	21
Interest rate			40			—			40
Foreign currency			2			—			2
Total current derivative assets(1)			61			2			63
Noncurrent Assets
Commodity			14			—			14
Interest rate			15			—			15
Total noncurrent derivative assets(2)			29			—			29
Total derivative assets		$	90		$	2		$	92
LIABILITIES
Current Liabilities
Commodity		$	2		$	54		$	56
Interest rate			3			—			3
Total current derivative liabilities(3)			5			54			59
Noncurrent Liabilities
Commodity			1			—			1
Total noncurrent derivative liabilities(4)			1			—			1
Total derivative liabilities		$	6		$	54		$	60

 

(1)	Current derivative assets are presented in other current assets on our Consolidated Balance Sheet.

(2)	Noncurrent derivative assets are presented in other deferred charges and other assets on our Consolidated Balance Sheet.

(3)	Current derivative liabilities are presented in other current liabilities on our Consolidated Balance Sheet.

(4)	Noncurrent derivative liabilities are presented in other deferred credits and other liabilities on our Consolidated Balance Sheet.

 

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

The following tables present the gains and losses on our derivatives, as well as where the associated activity is presented on our Consolidated Balance Sheet and Consolidated Statements of Income:

 

Derivatives in cash flow hedging relationships		Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)				Amount of Gain (Loss) Reclassified from AOCI to Income				Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three months ended September 30, 2009
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases						$	(2	)
Purchased electric capacity							1
Total commodity		$	—				(1	)		$	4
Interest rate(3)			(3	)			—				(18	)
Foreign currency(4)			—				—				(2	)
Total		$	(3	)		$	(1	)		$	(16	)
Nine months ended September 30, 2009
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases						$	(8	)
Purchased electric capacity							4
Total commodity		$	(2	)			(4	)		$	9
Interest rate(3)			10				—				57
Foreign currency(4)			—				1				(2	)
Total		$	8			$	(3	)		$	64

 

(1)	Amounts deferred into AOCI have no associated effect in our Consolidated Statements of Income.

(2)	Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in our Consolidated Statements of Income.

(3)	Amounts recorded in our Consolidated Statements of Income are classified in interest and related charges.

(4)	Amounts recorded in our Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.

 

		Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Derivatives not designated as hedging instruments		Three Months Ended September 30, 2009				Nine Months Ended September 30, 2009
(millions)
Derivative Type and Location of Gains (Losses)
Commodity(2)		$	(14	)		$	(152	)

 

(1)	Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect on our Consolidated Statements of Income.

(2)	Amounts are recorded in electric fuel and other energy-related purchases in our Consolidated Statements of Income.

For the three and nine months ended September 30, 2009 there were no significant gains or losses recorded related to fair value hedging relationships.

See Note 6 for further information about fair value measurements and associated valuation methods for derivatives.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Note 8. Decommissioning Trust Investments

We hold marketable equity and debt securities and cash equivalents (classified as available-for-sale) and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for our nuclear plants. Our decommissioning trust funds are summarized below.

 

		Amortized Cost			Total Unrealized Gains(1)			Total Unrealized Losses(1)				Fair Value
(millions)
September 30, 2009
Marketable equity securities		$	503		$	111		$	—			$	614
Marketable debt securities:
Corporate bonds			149			10			(1	)			158
U.S. Treasury securities and agency debentures			106			4			—				110
State and municipal			169			12			—				181
Other			1			—			—				1
Cost method investments			94			—			—				94
Cash equivalents and other(2)			22			—			—				22
Total		$	1,044		$	137		$	(1	)(3)		$	1,180
December 31, 2008
Marketable equity securities		$	459		$	9		$	—			$	468
Marketable debt securities:
Corporate bonds			144			7			—				151
U.S. Treasury securities and agency debentures			122			4			—				126
State and municipal			177			6			—				183
Cost method investments			108			—			—				108
Cash equivalents and other(2)			17			—			—				17
Total		$	1,027		$	26		$	—			$	1,053

 

(1)	Included in AOCI and the decommissioning trust regulatory liability.

(2)	Includes net assets related to pending sales and purchases of securities of $7 million and $6 million at September 30, 2009 and December 31, 2008, respectively.

(3)	The fair value of securities in an unrealized loss position was $34 million at September 30, 2009.

The fair value of our marketable debt securities at September 30, 2009, by contractual maturity is as follows:

 

		Amount
(millions)
Due in one year or less		$	18
Due after one year through five years			108
Due after five years through ten years			165
Due after ten years			159
Total		$	450

Presented below is selected information regarding our marketable equity and debt securities.

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2009			2008			2009			2008
(millions)
Proceeds from sales(1)		$	277		$	94		$	607		$	303
Realized gains(2)			60			5			83			22
Realized losses(2)			16			32			86			82

 

(1)	The increase in proceeds primarily reflects changes in asset allocation and liquidation of positions in connection with changes in fund managers.

(2)	Includes realized gains and losses recorded to the decommissioning trust regulatory liability.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

We recorded other-than-temporary impairment losses on investments as follows:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
(millions)
Total other-than-temporary impairment losses(1)		$	7			$	26			$	89			$	66
Losses recorded to decommissioning trust regulatory liability			(6	)			(22	)			(76	)			(56	)
Net impairment losses recognized in earnings		$	1			$	4			$	13			$	10

 

(1)	Amount includes other-than-temporary impairment losses for debt securities of $1 million and $13 million for the three months ended September 30, 2009 and 2008, respectively, and $6 million and $21 million for the nine months ended September 30, 2009 and 2008, respectively.

Note 9. Regulatory Assets and Liabilities

Our regulatory assets and liabilities include the following:

 

		September 30, 2009			December 31, 2008
(millions)
Regulatory assets
Deferred cost of fuel used in electric generation(1)		$	295		$	133
Other			99			79
Regulatory assets – current			394			212
RTO start-up costs and administration fees(2)			120			122
Deferred cost of fuel used in electric generation(1)			—			676
Other			155			123
Regulatory assets – non-current			275			921
Total regulatory assets		$	669		$	1,133
Regulatory liabilities
Provision for future cost of removal(3)		$	548		$	506
Decommissioning trust(4)			299			213
Other(5)			103			61
Total regulatory liabilities		$	950		$	780

 

(1)	Primarily reflects deferred fuel expenses for the Virginia jurisdiction. See Note 13 for more information.

(2)

See Note 13 regarding FERC approval of our recovery of start-up costs incurred in connection with joining an RTO and ongoing administrative charges paid to PJM through Deferral Recovery Charge (DRC). At September 30, 2009, approximately $20 million of these costs were included in other current regulatory assets.

(3)	Rates charged to customers by our regulated business include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.

(4)

Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of our utility nuclear generation stations, in excess of the related ARO.

(5)	Includes $15 million and $20 million reported in other current liabilities at September 30, 2009 and December 31, 2008, respectively.

At September 30, 2009, approximately $389 million of our regulatory assets represented past expenditures on which we do not earn a return. These expenditures consist primarily of deferred fuel costs that are expected to be recovered within the next twelve months.

 

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Note 10. Asset Retirement Obligations

The following table describes the changes in our AROs during 2009:

 

		Amount
(millions)
AROs at December 31, 2008(1)		$	717
Revisions in estimated cash flows(2)			(115	)
Accretion			26
AROs at September 30, 2009(1)		$	628

 

(1)	Includes $2 million reported in other current liabilities at December 31, 2008 and September 30, 2009.

(2)	Primarily reflects updated decommissioning cost studies and applicable escalation rates received for each of our nuclear facilities during the second quarter of 2009.

Note 11. Variable Interest Entities

As discussed in Note 13 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008, certain variable pricing terms in some of our long-term power and capacity contracts cause them to be considered variable interests in the counterparties.

We have long-term power and capacity contracts with four non-utility generators with an aggregate generation capacity of approximately 940 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that we consider to be variable interests. After an evaluation of the information provided to us by these entities, we were unable to determine whether they were variable interest entities (VIEs). However, the information they provided, as well as our knowledge of generation facilities in Virginia, enabled us to conclude that, if they were VIEs, we would not be the primary beneficiary. This conclusion was based primarily on a qualitative assessment of our variable interests as compared to the operations, commodity price and other risks retained by the equity and debt holders during the remaining terms of our contracts and for the years the entities are expected to operate after our contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. We are not subject to any risk of loss from these potential VIEs other than our remaining purchase commitments which totaled $1.8 billion as of September 30, 2009. We paid $52 million and $50 million for electric capacity and $24 million and $60 million for electric energy to these entities for the three months ended September 30, 2009 and 2008, respectively. We paid $156 million and $152 million for electric capacity and $90 million and $153 million for electric energy to these entities for the nine months ended September 30, 2009 and 2008, respectively.

We purchased shared services from Dominion Resources Services, Inc. (DRS), an affiliated VIE, of $108 million and $98 million for the three months ended September 30, 2009 and 2008, respectively, and $307 million and $273 million for the nine months ended September 30, 2009 and 2008, respectively. We determined that we are not the most closely associated entity with DRS and therefore not the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including us. We have no obligation to absorb more than our allocated share of DRS costs.

Note 12. Significant Financing Transactions

Joint Credit Facilities, Affiliated Borrowings and Short-Term Debt

We use short-term debt, primarily commercial paper, and affiliated borrowings 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.

Our short-term financing is supported by a $2.9 billion five-year joint revolving credit facility with Dominion dated February 2006, which 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 and us and for 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, 2009, there was no outstanding commercial paper supported by the joint credit facility, and the total outstanding letters of credit supported by the joint credit facility were $252 million, of which $183 million were issued on our behalf.

At September 30, 2009, capacity available under the joint credit facility was $2.6 billion.

 

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

In addition to the credit facility commitments of $2.9 billion disclosed above, we also have a five-year $120 million syndicated credit facility that can be used to support certain of our tax-exempt financings.

The following table presents our borrowings from Dominion under short-term arrangements:

 

		September 30, 2009			December 31, 2008
(millions)
Outstanding borrowings, net of repayments, under the Dominion money pool for our nonregulated subsidiaries		$	62		$	198
Short-term demand note borrowings from Dominion			1,000			219
Total affiliated borrowings		$	1,062		$	417

Interest charges related to our borrowings from Dominion were not material for the three or nine months ended September 30, 2009 and 2008.

Long-Term Debt

In May 2009, we borrowed $40 million in connection with the Economic Development Authority of the County of Chesterfield Pollution Control Refunding Revenue Bonds, Series 2009 A, which mature in 2023 and bear a coupon rate of 5.0%. The proceeds were used to refund the principal amount of the Industrial Development Authority of the County of Chesterfield Money Market Municipals ^TM Pollution Control Revenue Bonds, Series 1985 that would otherwise have matured in October 2009.

In May 2009, we borrowed $70 million in connection with the Economic Development Authority of York County, Virginia Pollution Control Refunding Revenue Bonds, Series 2009 A, which mature in 2033 and bear an initial coupon rate of 4.05% for the first five years, after which they will bear interest at a market rate to be determined at that time using a remarketing process. The proceeds were used to refund the principal amount of the Industrial Development Authority of York County, Virginia Money Market Municipals^TM Pollution Control Revenue Bonds, Series 1985 that would otherwise have matured in July 2009.

In June 2009, we issued $350 million of 5.0% senior notes that mature in 2019. The proceeds were used for general corporate purposes and the repayment of short term debt, including commercial paper.

In September 2009, we borrowed $60 million in connection with the $160 million Industrial Development Authority of Wise County Solid Waste and Sewage Disposal Revenue Bonds, Series 2009 A, which mature in 2040 and bear interest during the initial period at a variable rate. Due to unfavorable market conditions, we acquired the $60 million in bonds upon issuance in September 2009 with the intention of remarketing them to a third party at a later time. Proceeds will be used to finance facilities at the Virginia City Hybrid Energy Center. As of September 30, 2009, these bonds have not been remarketed and thus are eliminated in consolidation, along with the investment.

We repaid $120 million of long-term debt during the nine months ended September 30, 2009.

Note 13. Commitments and Contingencies

Other than the following matters, there have been no significant developments regarding the commitments and contingencies disclosed in Note 20 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008, or Note 8 and Note 12 to the Consolidated Financial Statements in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009, respectively, nor have any significant new matters arisen during the three months ended September 30, 2009.

Electric Regulation in Virginia

2007 Virginia Regulation Act

Pursuant to the Virginia Electric Utility Regulation Act (the Regulation Act), the Virginia Commission entered an order in January 2009 initiating reviews of the base rates and terms and conditions of all investor-owned electric utilities in Virginia. Possible outcomes of the 2009 rate review, according to the Regulation Act, include a rate increase, a rate decrease, or a partial refund of 2008 earnings more than 50 basis points above the authorized return on equity (ROE).

During 2009, we submitted base rate filings and accompanying schedules to the Virginia Commission, which, as amended, propose to increase our Virginia jurisdictional base rates by approximately $250 million annually. Our

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

initial March 2009 filing proposed a 12.5% ROE, plus an additional 100 basis point performance incentive pursuant to the Regulation Act based on our generating plant performance, customer service, and operating efficiency, resulting in a total ROE request of 13.5%. In July 2009, in response to rulings by the Virginia Commission relating to the appropriate rate year and capital structure to be used in the Company’s base rate review, we submitted a revised filing reflecting a number of adjustments, including an upward adjustment of 50 basis points in the proposed ROE. The base rate increase became effective on an interim basis on September 1, 2009, subject to refund and adjustment by the Virginia Commission and increases a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $5.22 per month. An evidentiary hearing on our base rate filing is scheduled to be held in January 2010.

In March 2009, we filed with the Virginia Commission, pursuant to the Regulation Act, a petition to recover from Virginia jurisdictional customers an annual net increase of approximately $78 million in costs related to FERC-approved transmission charges and PJM demand response programs. This amount also included a portion of costs discussed further in the RTO Start-up Costs and Administrative Fees section. In a final order in June 2009, the Virginia Commission approved a new rate adjustment clause (Rider T) to recover approximately $218 million over the 12-month period beginning September 1, 2009, subject to an annual review and re-set in 2010, if necessary. The approved amount to be recovered through Rider T includes approximately $150 million of transmission-related costs that were traditionally incorporated in base rates, plus an incremental increase of approximately $68 million. The Virginia Commission also ruled that approximately $10 million that the Company had proposed to collect in Rider T would be more appropriately recovered through base rates, and those costs have been incorporated into the Company’s revised base rate filing that was submitted in July 2009. Rider T became effective on September 1, 2009, and increases a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.11 per month.

In July 2009, we filed with the Virginia Commission an application for approval and cost recovery of twelve demand-side management (DSM) programs, including one peak-shaving program and eleven energy efficiency programs. We plan to use DSM, along with our traditional and renewable supply-side resources, to meet our projected load growth over the next 15 years. The DSM programs provide the first steps toward achieving Virginia’s goal of reducing, by 2022, the electric energy consumption of the Company’s retail customers by ten percent of what was consumed in 2006. The Virginia Commission has set an evidentiary hearing for February 16, 2010, to consider the DSM programs and the related recovery. The Company has requested approval of two rate adjustment clauses for the associated cost recovery to be effective April 1, 2010. Specifically, the two rate adjustment clauses for recovery from Virginia jurisdictional customers represent an annual net increase in costs of approximately $51 million for the period April 1, 2010 to March 31, 2011. If approved by the Virginia Commission, the rate adjustment clauses will be expected, on a combined basis, to increase a typical 1,000 kWh residential bill by approximately $0.95 per month. The Regulation Act gives the Virginia Commission until the end of March 2010 to act on our application.

Virginia Fuel Expenses

In March 2009, we filed our Virginia fuel factor application with the Virginia Commission. The application requested an annual decrease in fuel expense recovery of approximately $236 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.893 cents per kWh to 3.529 cents per kWh, or approximately $3.64 per month for the typical 1,000 kWh Virginia jurisdictional residential customer’s average bill. The proposed fuel factor went into effect on July 1, 2009 on an interim basis and an evidentiary hearing on the Company’s application was held on September 1, 2009. Consistent with a proposal made by the Company at the hearing in September 2009, the Virginia Commission issued an interim fuel order, effective October 1, 2009, further reducing the fuel factor by approximately $103 million for the period July 1, 2009 through June 30, 2010. The cumulative decrease in the fuel factor for the period July 1, 2009 through June 30, 2010 reflects lower projected fuel expenses and a prospective credit against fuel expenses of certain financial transmission rights (FTRs) allocated to the Company. The Virginia Commission has not yet issued a final order.

Generation Expansion

In March 2009, we filed with the Virginia Commission our first annual update to the rate adjustment clause for the Virginia City Hybrid Energy Center requesting an increase of approximately $99 million for financing costs to be recovered through rates in 2010. As part of this filing we requested that the 13.5% ROE proposed in our March 31, 2009 base rate filing be applied to the Virginia City Hybrid Energy Center rate adjustment clause (Rider S), plus the 100 basis point enhancement for construction of a new coal-fired generation facility as previously authorized by the Virginia Commission pursuant to the Regulation Act, for a requested total ROE of 14.5%. If approved by the Virginia Commission, the revised Rider S could become effective as early as January 1, 2010 as requested by the Company and would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

approximately $1.78 per month. An evidentiary hearing was held before a hearing examiner in August 2009, at which we presented a proposed stipulation and recommendation that, among other things, would reduce the revenue requirement by approximately $8 million to $91 million, the result of which would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.63 per month. No report has yet been issued by the hearing examiner.

In June 2008, the Virginia State Air Pollution Control Board approved and issued an air permit to construct and operate the Virginia City Hybrid Energy Center and also approved and issued another air permit for hazardous emissions. Construction of the Virginia City Hybrid Energy Center commenced and the facility is expected to be in operation by 2012. In August 2008, the Southern Environmental Law Center (SELC), on behalf of four environmental groups, filed Petitions for Appeal in Richmond Circuit Court challenging the approval of both of the air permits. The Richmond Circuit Court issued an Order in September 2009 upholding the initial air permit and upholding the second air permit for hazardous emissions except for one condition related to the permit limit for mercury emissions. The hazardous emissions air permit was amended by the Virginia Department of Environmental Quality in September 2009 to comply with the Richmond Circuit Court Order. The permit amendment does not impact the project. In October 2009, a Notice of Appeal of the court’s Order regarding the initial air permit was filed with the Richmond Circuit Court by several environmental groups, initiating the appeals process to the Court of Appeals.

In March 2009, the Virginia Commission authorized construction and operation of our proposed Bear Garden facility, a 580 MW (nominal) natural gas- and oil-fired combined-cycle electric generating facility and associated transmission interconnection facilities in Buckingham County, Virginia, estimated to cost $619 million, excluding financing costs. In March 2009, we also filed a petition with the Virginia Commission for the initiation of a rate adjustment clause for recovery of approximately $77 million in financing costs related to the construction of the Bear Garden facility to be recovered through rates in 2010. As part of this filing we requested that the 13.5% ROE proposed in our March 31, 2009 base rate filing be applied to the Bear Garden facility rate adjustment clause, with a 100 basis point enhancement for construction of a combined-cycle facility, as authorized by the Regulation Act, for a requested total ROE of 14.5%. If approved by the Virginia Commission, the rate adjustment clause could become effective as early as January 1, 2010 as requested by the Company. An evidentiary hearing was held before a hearing examiner in August 2009. In the Company’s post-hearing brief, it unilaterally agreed to reduce the revenue requirement by $4 million to $73 million, the result of which would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.33 per month. No report has yet been issued by the hearing examiner.

We are unable to predict the outcome of the Virginia Commission’s future rate actions, including actions relating to our 2009 base rate review, our DSM programs, our recovery of Virginia fuel expenses, and our additional rate adjustment clause filings; however, unfavorable future decisions by the Virginia Commission could adversely affect our results of operations, financial condition and cash flows.

RTO Start-up Costs and Administrative Fees

In December 2008, FERC approved our DRC request to become effective January 1, 2009, which would allow recovery of approximately $153 million of RTO costs ($140 million of our costs and $13 million of Dominion’s costs) that were deferred due to a statutory base rate cap established under Virginia law. In June 2009, the Virginia Commission approved full recovery of the DRC from retail customers through Rider T. Recovery of the DRC began September 1, 2009. In July 2009, FERC issued an order denying the Virginia Attorney General’s office and the Virginia Commission’s requests for rehearing of its December 2008 order. Notices of appeal were filed in September 2009 at the U.S. Court of Appeals for the Fourth Circuit and the appeal is currently pending. We cannot predict the outcome of the appeal.

Guarantees and Surety Bonds

As of September 30, 2009, we had issued $16 million of guarantees primarily to support tax-exempt debt. We had also purchased $89 million of surety bonds for various purposes, including providing workers’ compensation coverage. Under the terms of surety bonds, we are obligated to indemnify the respective surety bond company for any amounts paid.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Litigation

We are co-owners with Old Dominion Electric Cooperative of the Clover power station. We have been in litigation with Norfolk Southern Railway Company (Norfolk Southern) regarding a long term coal transportation agreement for the delivery of coal to the facility. The trial court agreed with Norfolk Southern’s interpretation that the agreement specifies the use of an index (NS Index) which Norfolk Southern claims should have been applied to adjust the base rate and which should be applied going forward. The trial court assessed damages of approximately $78 million for the contract period from December 1, 2003 through November 30, 2007 and imposed prejudgment interest of approximately $9 million. Our share would have been one-half of the total judgment, or approximately $44 million. On appeal, the Supreme Court of Virginia in September 2009 affirmed the decisions of the trial court on all issues except for the calculation of damages. The Supreme Court of Virginia remanded the case to the trial court to recalculate damages in accordance with its opinion. We expect that the recalculation will reduce damages, with interest, to approximately $10 million as of September 30, 2009. We have recorded a liability in the Consolidated Financial Statements for our one-half share of the expected judgment. We do not believe that final resolution of this matter will materially impact our results of operations or financial condition.

Note 14. Credit Risk

Credit risk is our risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. We believe, based on our credit policies, that it is unlikely 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, 2009, our gross credit exposure totaled $36 million. After the application of collateral, our credit exposure is reduced to $25 million. Of this amount, investment grade counterparties, including those internally rated, represented 76%, and no single counterparty exceeded 36%.

The majority of our derivative instruments contain credit-related contingent provisions. These provisions require us to provide collateral upon the occurrence of specific events, primarily a credit downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of September 30, 2009, we would not be required to post any additional collateral to our counterparties. This determination includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. As of September 30, 2009, we have not posted any collateral related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of September 30, 2009 is $1 million and does not include the impact of any offsetting asset positions. See Note 7 for further information about our derivative instruments.

Note 15. Related Party Transactions

We engage in related-party transactions primarily with other Dominion subsidiaries (affiliates). Our receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. We are included in Dominion’s consolidated federal income tax return and participate in certain Dominion benefit plans. See Note 12 for information about affiliated borrowings. A discussion of other 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. We also enter into certain commodity derivative contracts with affiliates. We use these contracts, which are principally comprised of commodity swaps and options, to manage commodity price risks associated with purchases of natural gas. We designate the majority of these contracts as cash flow hedges for accounting purposes.

 

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

We receive a variety of services from DRS and other affiliates, primarily for accounting, legal, finance and certain administrative and technical services. In addition, we provide certain services to affiliates, including charges for facilities and equipment usage.

Presented below are significant transactions with DRS and other affiliates:

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2009			2008			2009			2008
(millions)
Commodity purchases from affiliates		$	109		$	255		$	263		$	441
Services provided by affiliates			109			98			310			274

Note 16. Operating Segments

We are organized primarily on the basis of the products and services we sell. 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 DVP and Generation segments. We manage our daily operations through the following segments:

DVP includes our transmission, distribution and customer service operations.

Generation includes our generation and energy supply operations.

Corporate and Other primarily includes specific items attributable to our operating segments. The contribution to net income by our primary operating segments is determined based on a measure of profit that 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, either in assessing the segment’s performance or in allocating resources among the segments and are instead reported in the Corporate and Other segment. For the nine months ended September 30, 2009 and 2008, the Corporate and Other segment included $6 million and $7 million, respectively, of after-tax expenses attributable to our operating segments.

The net expenses in 2009 primarily resulted from $6 million ($4 million after-tax) of expenses attributable to the Generation segment, reflecting net losses on investments in our nuclear decommissioning trusts.

The net expenses in 2008 primarily resulted from $6 million ($4 million after-tax) of expenses attributable to the Generation segment, reflecting a contribution to fund certain non-generation improvements.

The following table presents segment information pertaining to our operations:

 

		DVP			Generation			Corporate and Other				Consolidated Total
(millions)
Three Months Ended September 30, 2009
Operating revenue		$	374		$	1,564		$	—			$	1,938
Net income (loss)			83			233			(1	)			315
Three Months Ended September 30, 2008
Operating revenue		$	374		$	1,797		$	6			$	2,177
Net income (loss)			83			227			(7	)			303
Nine Months Ended September 30, 2009
Operating revenue		$	1,107		$	4,365		$	—			$	5,472
Net income (loss)			249			426			(7	)			668
Nine Months Ended September 30, 2008
Operating revenue		$	1,092		$	4,143		$	12			$	5,247
Net income (loss)			226			509			(10	)			725

 

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VIRGINIA ELECTRIC AND POWER COMPANY

 

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MD&A discusses our results of operations and general financial condition. MD&A should be read in conjunction with our Consolidated Financial Statements. 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 or more of its consolidated subsidiaries or operating segments, or the entirety of Virginia Electric and Power Company and its consolidated subsidiaries. All of our common stock is owned by our parent company, 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

 

•

Liquidity and Capital Resources

 

•

Future Issues and Other Matters

Forward-Looking Statements

This report contains statements concerning 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,” “target” 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, high winds and severe storms, that can cause outages and property damage to our facilities;

 

•

Federal, state and local legislative and regulatory developments;

 

•

Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for greenhouse gases and other emissions, more extensive permitting requirements and the regulation of additional substances;

 

•

Cost of environmental compliance, including those costs related to climate change;

 

•

Risks associated with the operation of nuclear facilities;

 

•

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

 

•

Capital market conditions, including the availability of credit and our ability to obtain financing on reasonable terms;

 

•

Risks associated with our membership and participation in PJM related to obligations created by the default of other participants;

 

•

Price risk due to marketable securities held as investments in nuclear decommissioning trusts;

 

•

Fluctuations in interest rates;

 

•

Changes in federal and state tax laws and regulations;

 

•

Changes in rating agency requirements or credit ratings and their 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 regulated electric rates collected by the Company, including the outcome of our 2009 rate filings;

 

•

Timing and receipt of regulatory approvals necessary for planned construction or expansion projects;

 

•

The inability to complete planned construction or expansion projects within the terms and time frames initially anticipated;

 

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•

Changes in rules for the RTO in which we participate, including changes in rate designs and capacity models;

 

•

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

 

•

Adverse outcomes in litigation matters.

Additionally, other factors that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2008.

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, 2009, there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008, other than the impact of updated nuclear decommissioning cost studies on our AROs as discussed in Note 10 to our Consolidated Financial Statements. The policies disclosed included the accounting for derivative contracts and other instruments at fair value, regulated operations, AROs, unbilled revenue and income taxes.

Results of Operations

Presented below is a summary of our consolidated results:

 

		Third Quarter									Year-To-Date
		2009			2008			$ Change			2009			2008			$ Change
(millions)
Net income		$	315		$	303		$	12		$	668		$	725		$	(57	)

Overview

Third Quarter 2009 vs. 2008

Net income increased 4% to $315 million, primarily reflecting a decrease in outage costs related to fewer scheduled outages at certain of our generating facilities.

Year-To-Date 2009 vs. 2008

Net income decreased 8% to $668 million, primarily reflecting a reduced benefit from FTRs reflecting lower fuel prices, and an increase in outage costs related to scheduled outages at certain of our fossil generating facilities.

Analysis of Consolidated Operations

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

 

		Third Quarter										Year-To-Date
		2009			2008			$ Change				2009			2008			$ Change
(millions)
Operating Revenue		$	1,938		$	2,177		$	(239	)		$	5,472		$	5,247		$	225
Operating Expenses
Electric fuel and other energy-related purchases			740			974			(234	)			2,219			1,971			248
Purchased electric capacity			95			102			(7	)			307			305			2
Other operations and maintenance			339			340			(1	)			1,067			1,009			58
Depreciation and amortization			162			154			8				479			453			26
Other taxes			48			46			2				145			140			5
Other income			33			6			27				65			24			41
Interest and related charges			89			82			7				263			239			24
Income tax expense			183			182			1				389			429			(40	)

 

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An analysis of our results of operations follows:

Third Quarter 2009 vs. 2008

Operating Revenue decreased 11%, primarily reflecting:

 

•

A $141 million decrease in fuel revenue largely due to the impact of a comparatively lower fuel rate in certain customer jurisdictions implemented in July 2009, including the recovery of previously deferred fuel expenses;

 

•

A $97 million decrease in sales to wholesale customers due to decreased volumes ($67 million) and lower prices ($30 million); and

 

•

A $34 million decrease in base revenues from sales to retail customers due to a 9% decrease in cooling degree days; partially offset by

 

•

A $22 million increase due to the impact of a rate adjustment clause associated with the recovery of financing costs for the Virginia City Hybrid Energy Center; and

 

•

A $19 million increase in base revenues primarily due to higher interim base rates implemented in September 2009 for certain customer jurisdictions.

Operating Expenses and Other Items

Electric fuel and other energy-related purchases expense decreased 24%, primarily reflecting a comparatively lower fuel rate in certain customer jurisdictions, including the recovery of previously deferred fuel expenses ($144 million) and a decrease in fuel expenses associated with wholesale customers ($85 million).

Other income increased by $27 million, reflecting a $12 million increase primarily due to an increase in the equity component of AFUDC as a result of construction and expansion projects, and an increase resulting from net realized gains in 2009 as compared to net realized losses in 2008 on investments held in our nuclear decommissioning trusts for jurisdictions that are not subject to cost-based regulation ($7 million).

Year-To-Date 2009 vs. 2008

Operating Revenue increased 4%, primarily reflecting:

 

•

A $358 million increase in fuel revenue largely due to the impact of a comparatively higher fuel rate in certain customer jurisdictions, including the recovery of previously deferred fuel expenses;

 

•

A $66 million increase due to the impact of a rate adjustment clause associated with the recovery of financing costs for the Virginia City Hybrid Energy Center;

 

•

A $20 million increase from new retail customer connections primarily in our residential customer class; and

 

•

A $20 million increase in base revenues from sales to retail customers due to a 19% increase in heating degree days, partially offset by a 9% decrease in cooling degree days.

These increases were partially offset by:

 

•

A $181 million decrease in sales to wholesale customers due to decreased volumes ($102 million) and lower prices ($79 million);

 

•

A $35 million decrease in base revenues reflecting the impact of unfavorable economic conditions on customer usage and other factors; and

 

•

A $25 million decrease resulting from lower ancillary services revenue reflecting lower regulation and frequency response revenue and operating reserves revenue received from PJM market operations.

Operating Expenses and Other Items

Electric fuel and other energy-related purchases expense increased 13%, primarily reflecting a comparatively higher fuel rate in certain customer jurisdictions, including the recovery of previously deferred fuel expenses ($339 million) and a reduced benefit from FTRs ($44 million), partially offset by a decrease in fuel expenses associated with wholesale customers ($135 million).

Other operations and maintenance expense increased 6%, primarily reflecting:

 

•

A $32 million increase in outage costs related to scheduled outages primarily at certain fossil generating facilities;

 

•

A $30 million increase resulting from higher salaries, wages and benefits largely due to higher pension and other postretirement benefit costs;

 

•

A $27 million decrease in gains from the sale of emissions allowances; and

 

•

A $21 million increase in bad debt expense; partially offset by

 

•

A $30 million decrease due to the deferral of transmission-related expenditures collectible under certain rate adjustment clauses; and

 

•

A $19 million decrease reflecting lower storm damage and service restoration costs associated with our distribution operations.

 

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Other income increased by $41 million, reflecting a $20 million increase primarily due to an increase in the equity component of AFUDC as a result of construction and expansion projects, greater charitable contributions in the comparable prior year period ($9 million) and an increase in amounts collectible from customers for taxes in connection with contributions in aid of construction ($7 million).

Interest and related charges increased 10%, largely due to the impact of additional borrowings.

Income tax expense decreased 9%, reflecting lower pre-tax income in 2009.

Segment Results of Operations

Presented below is a summary of contributions by our operating segments to net income:

 

		Third Quarter											Year-To-Date
		2009				2008				$ Change			2009				2008				$ Change
(millions)
DVP		$	83			$	83			$	—		$	249			$	226			$	23
Generation			233				227				6			426				509				(83	)
Primary operating segments			316				310				6			675				735				(60	)
Corporate and Other			(1	)			(7	)			6			(7	)			(10	)			3
Consolidated		$	315			$	303			$	12		$	668			$	725			$	(57	)

DVP

Presented below are operating statistics related to our DVP operations:

 

		Third Quarter							Year-To-Date
		2009		2008		% Change			2009		2008		% Change
Electricity delivered (million MWh)		21.8		23.4		(7	)%		62.1		64.2		(3	)%
Degree days:
Cooling(1)		988		1,083		(9	)		1,451		1,587		(9	)
Heating(2)		5		2		150			2,462		2,074		19
Average retail customer accounts (thousands)(3)		2,403		2,387		1			2,401		2,383		1

 

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

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

(3)	Period average.

 

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

 

		Third Quarter 2009 vs. 2008 Increase (Decrease)				Year-To-Date 2009 vs. 2008 Increase (Decrease)
(millions)
Storm damage and service restoration – distribution operations		$	3			$	12
Regulated electric sales:
Weather			(7	)			6
Customer growth			1				4
Rate adjustment clause(1)			3				3
Other(2)			2				(8	)
Other(3)			(2	)			6
Change in net income contribution		$	—			$	23

 

(1)	Reflects the impact of a new rate adjustment clause associated with the recovery of transmission-related expenditures.

(2)	Year-to-date decrease primarily reflects the impact of unfavorable economic conditions on customer usage and other factors.

(3)	Year-to-date increase primarily reflects the deferral of transmission-related expenditures collectible under a rate adjustment clause.

Generation

Presented below are operating statistics related to our Generation operations:

 

		Third Quarter							Year-To-Date
		2009		2008		% Change			2009		2008		% Change
Electricity supplied (million MWh)		21.8		23.4		(7	)%		62.1		64.2		(3	)%
Degree days:
Cooling		988		1,083		(9	)		1,451		1,587		(9	)
Heating		5		2		150			2,462		2,074		19

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

 

		Third Quarter 2009 vs. 2008 Increase (Decrease)				Year-To-Date 2009 vs. 2008 Increase (Decrease)
(millions)
Outage costs		$	8			$	(20	)
Sales of emissions allowances			—				(17	)
Regulated electric sales:
Weather			(14	)			6
Rate adjustment clause(1)			14				40
Customer growth			3				8
Other(2)			(5	)			(45	)
Ancillary service revenue			(4	)			(17	)
Depreciation and amortization			(3	)			(11	)
Other(3)			7				(27	)
Change in net income contribution		$	6			$	(83	)

 

(1)	Reflects the impact of a new rate adjustment clause associated with the recovery of construction-related financing costs for the Virginia City Hybrid Energy Center.

(2)	Year-to-date decrease reflects lower sales to wholesale customers, as well as the impact of unfavorable economic conditions on customer usage and other factors.

(3)	Year-to-date decrease primarily reflects lower settlement gains on FTRs.

 

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Liquidity and Capital Resources

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 issuances of debt and/or equity securities.

At September 30, 2009, we had $2.6 billion of unused capacity under our joint credit facility.

A summary of our cash flows is presented below:

 

		2009				2008
(millions)
Cash and cash equivalents at January 1,		$	27			$	49
Cash flows provided by (used in)
Operating activities			1,586				945
Investing activities			(1,905	)			(1,376	)
Financing activities			315				409
Net decrease in cash and cash equivalents			(4	)			(22	)
Cash and cash equivalents at September 30,		$	23			$	27

Operating Cash Flows

Net cash provided by operating activities increased by $641 million, primarily due to higher deferred fuel cost recoveries in our Virginia jurisdiction and a favorable change in customer receivables, partially offset by higher income tax payments. We believe that our operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and provide dividends to Dominion. However, our operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, which are discussed in Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2008.

Credit Risk

As discussed in Note 14 to our Consolidated Financial Statements, our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Presented below is a summary of our gross credit exposure as of September 30, 2009, 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			Credit Collateral			Net Credit Exposure
(millions)
Investment grade(1)		$	28		$	11		$	17
Non-investment grade(2)			6			—			6
No external ratings:
Internally rated—investment grade(3)			2			—			2
Internally rated—non-investment grade			—			—			—
Total		$	36		$	11		$	25

 

(1)	Designations as investment grade are based on minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 67% of the total net credit exposure.

(2)	The only counterparty exposure for this category represented approximately 26% of the total net credit exposure.

(3)	The two counterparty exposures, combined, for this category represented approximately 7% of the total net credit exposure.

Investing Cash Flows

Net cash used in investing activities increased by $529 million, primarily reflecting an increase in capital expenditures for generation and transmission construction projects, including our Virginia City Hybrid Energy Center.

 

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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 impacted by capital market conditions and subject to meeting certain regulatory requirements, including registration with the SEC and approval from the Virginia Commission.

Net cash provided by financing activities decreased by $94 million, primarily due to lower net debt issuances as a result of higher cash inflows from operating activities.

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

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 the Credit Ratings and Debt Covenants sections of MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008, we discussed the 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, 2009, there have been no changes in our credit ratings, nor have there been any changes to or events of default under our debt covenants. In April 2009, Moody’s revised its credit ratings outlook for the Company to positive from stable.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of September 30, 2009, there have been no material changes outside the ordinary course of business to our contractual obligations nor any material changes to our planned capital expenditures disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008.

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 Item 1. Business and Future Issues and Other Matters in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008 and Future Issues and Other Matters in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009. In addition, see Note 13 to our Consolidated Financial Statements and Part II, Item 1. Legal Proceedings for additional information on various environmental, regulatory, legal and other matters that may impact our future results of operations and/or financial condition, including a discussion of electric regulation in Virginia.

Federal Regulation

Federal Energy Regulatory Commission

In January 2008, FERC affirmed an earlier decision that the PJM transmission rate design for existing facilities had not become unjust and unreasonable. For recovery of costs of investments of new PJM-planned transmission facilities that operate at or above 500 kilovolt (kV), FERC established a regional rate design where all customers pay a uniform rate based on the costs of such investment. For recovery of costs of investment in new PJM-planned transmission facilities that operate below 500 kV, FERC affirmed its earlier decision to allocate costs on a beneficiary pays approach. A notice of appeal of this decision was filed in February 2008 at the U.S. Court of Appeals for the Seventh Circuit. In August 2009, the court denied the petition for review concerning the rate design for existing facilities, but granted the petition concerning the rate design for new facilities that operate at or above 500 kV, and remanded that issue back to FERC for further proceedings. We cannot predict the outcome of the FERC proceedings on remand.

In May 2008, the Maryland Public Service Commission, Delaware Public Service Commission, Pennsylvania Public Utility Commission, New Jersey Board of Public Utilities, the American Forest & Paper Association, the Portland Cement Association and several other organizations representing consumers in the PJM region (the RPM Buyers) filed a complaint at FERC claiming that PJM’s Reliability Pricing Model’s transitional auctions have produced unjust and unreasonable capacity prices. The RPM Buyers requested that a refund effective date of June 1, 2008 be established and that FERC provide appropriate relief from unjust and unreasonable capacity charges within 15 months. In September 2008, FERC dismissed the complaint. The RPM Buyers requested rehearing of the FERC order in October 2008 and rehearing was denied in June 2009. A notice of appeal was filed in August 2009 by the Maryland Public Service Commission and the New Jersey Board of Public Utilities at the U.S. Court of Appeals for the Fourth Circuit. We cannot predict the outcome of the appeal.

 

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Environmental Matters

We are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

Clean Water Act Compliance

In October 2007, the Virginia State Water Control Board (Water Board) issued a renewed water discharge (VPDES) permit for North Anna. The Blue Ridge Environmental Defense League, and other persons, appealed the Water Board’s decision to the Richmond Circuit Court, challenging several permit provisions related to North Anna’s discharge of cooling water. In February 2009, the court ruled that the Water Board was required to regulate the thermal discharge from North Anna into the waste heat treatment facility. We filed a motion for reconsideration with the court in February 2009, which was denied. The final order was issued by the court in September 2009. The court’s order allows North Anna to continue to operate pursuant to the currently issued VPDES permit. In October 2009, we filed a Notice of Appeal of the court’s Order with the Richmond Circuit Court, initiating the appeals process to the Court of Appeals. Until the final permit is reissued, it is not possible to predict any financial impact that may result.

Global Climate Change

In June 2009, the U.S. House of Representatives passed comprehensive legislation titled the “American Clean Energy and Security Act of 2009” to encourage the development of clean energy sources and reduce greenhouse gas (GHG) emissions. The legislation contains provisions establishing federal renewable energy standards for electric suppliers. The legislation also includes cap-and-trade provisions for the reduction of GHG emissions. Similar legislation has been introduced in the U.S. Senate. In addition, the EPA has proposed two rules that, if finalized, will hold that GHGs are air pollutants subject to the provisions of the Clean Air Act. These are the EPA Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (proposed April 2009) and the Proposed Rulemaking To Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards (proposed September 2009). The cost of compliance with future GHG emission reduction programs could be significant. Given the highly uncertain outcome and timing of future action by the U.S. federal government and states on this issue, we cannot predict the financial impact of future GHG emission reduction programs on our operations, shareholders or customers at this time.

 

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VIRGINIA ELECTRIC AND POWER COMPANY

 

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part I, Item 2. MD&A of this Form 10-Q. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2008 for discussion of various risks and uncertainties that may impact the Company.

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 and equity security prices as described below. Commodity price risk is due to our exposure to market shifts for prices paid for commodities. Interest rate risk is generally related to our outstanding debt and expected debt issuances. In addition, we are exposed to investment price risk through various portfolios of debt and 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 and interest rates.

Commodity Price Risk

To manage price risk, we hold commodity-based financial derivative instruments for non-trading purposes associated with purchases of electricity, natural gas and other energy-related products. 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, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices 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 observable market prices.

A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $1 million and $23 million in the fair value of our non-trading commodity-based financial derivatives as of September 30, 2009 and December 31, 2008, respectively. The decline in sensitivity is largely due to settlements of commodity derivative positions existing as of the beginning of the period.

The impact of a change in energy commodity prices on our non-trading 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 balance of fixed and variable rate debt. We may also enter into interest-rate swaps when deemed appropriate to adjust our exposure based upon market conditions. At September 30, 2009 and December 31, 2008, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of less than $1 million and approximately $2 million, respectively.

Additionally, we may use forward-starting interest-rate swaps and treasury rate locks as anticipatory hedges of future financings. At September 30, 2009, we had $850 million in aggregate notional amounts of these interest-rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $32 million in the fair value of these interest-rate derivatives at September 30, 2009. We did not have a significant amount of these interest-rate derivatives outstanding at December 31, 2008.

The impact of a change in market interest rates on these anticipatory hedges at a point in time is not necessarily representative of the results that will be realized when such contracts are settled. Net gains and/or losses from interest-rate derivatives used for anticipatory hedging purposes, to the extent realized, will generally be amortized over the life of the respective debt issuance being hedged.

 

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Investment Price Risk

We are subject to investment price risk due to securities held as investments in decommissioning trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in our Consolidated Balance Sheets at fair value.

We recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $7 million, $27 million and $57 million for the nine months ended September 30, 2009 and 2008 and for the year ended December 31, 2008, respectively. Net realized losses include gains and losses from the sale of investments as well as other-than-temporary impairments recognized in earnings. For the nine months ended September 30, 2009, we recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $130 million. For the nine months ended September 30, 2008 and for the year ended December 31, 2008, we recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $129 million and $233 million, respectively.

Dominion sponsors employee pension and other postretirement benefit plans, in which our employees participate, that hold investments in trusts to fund benefit payments. Investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that we will provide to Dominion for our share of employee benefit plan contributions.

 

ITEM 4.

CONTROLS AND PROCEDURES

Senior management, including our CEO and CFO, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, the CEO and CFO have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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VIRGINIA ELECTRIC AND POWER COMPANY

PART II. OTHER INFORMATION

 

ITEM 1.

LEGAL PROCEEDINGS

From time to time, we are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by us, or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, we are involved in various legal proceedings. We believe that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position, liquidity or results of operations. See Future Issues and Other Matters in MD&A and Note 13 to our Consolidated Financial Statements for discussions on various environmental, rate matters and other regulatory proceedings to which we are a party.

 

ITEM 1A.

RISK FACTORS

Our business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond our control. We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2008, which should be taken into consideration when reviewing the information contained in this report. There have been no material changes with regard to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.

 

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ITEM 6.

EXHIBITS

(a) Exhibits:

 

3.1		Restated Articles of Incorporation, as in effect on October 28, 2003 (Exhibit 3.1, Form 10-Q for the quarter ended September 30, 2003, File No. 1-2255, incorporated by reference).
3.2		Bylaws, as amended and restated on June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255, incorporated by reference).
12.1		Ratio of earnings to fixed charges (filed herewith).
12.2		Ratio of earnings to fixed charges and preferred dividends (filed herewith).
31.1		Certification by Registrant’s CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2		Certification by Registrant’s CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32		Certification to the SEC by Registrant’s CEO and CFO, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
99		Condensed consolidated earnings statements (unaudited) (filed herewith).

 

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SIGNATURE

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

 

		VIRGINIA ELECTRIC AND POWER COMPANY Registrant
November 2, 2009		/S/    ASHWINI SAWHNEY
		Ashwini Sawhney
		Vice President–Accounting (Chief Accounting Officer)

 

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EXHIBIT INDEX

 

3.1		Restated Articles of Incorporation, as in effect on October 28, 2003 (Exhibit 3.1, Form 10-Q for the quarter ended September 30, 2003, File No. 1-2255, incorporated by reference).
3.2		Bylaws, as amended and restated on June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255, incorporated by reference).
12.1		Ratio of earnings to fixed charges (filed herewith).
12.2		Ratio of earnings to fixed charges and preferred dividends (filed herewith).
31.1		Certification by Registrant’s CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
31.2		Certification by Registrant’s CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32		Certification to the SEC by Registrant’s CEO and CFO, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
99		Condensed consolidated earnings statements (unaudited) (filed herewith).

 

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