D 10-Q Quarterly Report Sept. 30, 2012

D 10-Q Quarter ended Sept. 30, 2012

DOMINION ENERGY, INC

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10-Q 1 d429453d10q.htm FORM 10-Q Form 10-Q

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, 2012

¨	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	Exact name of registrants as specified in their charters, address of principal executive offices and registrants’ telephone number	I.R.S. Employer Identification Number

001-08489	DOMINION RESOURCES, INC.	54-1229715

001-02255	VIRGINIA ELECTRIC AND POWER COMPANY	54-0418825
	120 Tredegar Street Richmond, Virginia 23219 (804) 819-2000

State or other jurisdiction of incorporation or organization of the registrants: Virginia

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.

Dominion Resources, Inc. Yes x No ¨ Virginia Electric and Power Company 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).

Dominion Resources, Inc. Yes x No ¨ Virginia Electric and Power Company Yes x 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.

Dominion Resources, Inc.

Virginia Electric and Power Company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Dominion Resources, Inc. Yes ¨ No x Virginia Electric and Power Company Yes ¨ No x

At September 30, 2012, the latest practicable date for determination, Dominion Resources, Inc. had 574,609,995 shares of common stock outstanding and Virginia Electric and Power Company had 274,723 shares of common stock outstanding. Dominion Resources, Inc. is the sole holder of Virginia Electric and Power Company’s common stock.

This combined Form 10-Q represents separate filings by Dominion Resources, Inc. and Virginia Electric and Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Virginia Electric and Power Company makes no representations as to the information relating to Dominion Resources, Inc.’s other operations.

COMBINED INDEX


		Page Number

	Glossary of Terms		3

	PART I. Financial Information

Item 1.	Financial Statements		6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		54
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		72
Item 4.	Controls and Procedures		73

	PART II. Other Information

Item 1.	Legal Proceedings		73
Item 1A.	Risk Factors		74
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		75
Item 6.	Exhibits		76

PAGE 2

GLOSSARY OF TERMS

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


Abbreviation or Acronym		Definition
AFUDC		Allowance for funds used during construction

AOCI		Accumulated other comprehensive income (loss)

ARO		Asset retirement obligation

ARP		Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the CAA

ATEX line		Appalachia to Texas Express ethane line

bcf		Billion cubic feet

Biennial Review Order		Order issued by the Virginia Commission in November 2011 concluding the 2009 - 2010 biennial review of Virginia Power’s base rates, terms and conditions

BOD		Board of Directors

Brayton Point		Brayton Point power station

Bremo		Bremo power station

CAA		Clean Air Act

CAIR		Clean Air Interstate Rule

CEO		Chief Executive Officer

CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980

CFO		Chief Financial Officer

CFTC		Commodity Futures Trading Commission

CO ₂		Carbon dioxide

Companies		Dominion and Virginia Power, collectively

Cooling degree days		Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day

Cove Point		Dominion Cove Point LNG, LP

CSAPR		Cross State Air Pollution Rule

CWA		Clean Water Act

DEI		Dominion Energy, Inc.

DOE		Department of Energy

Dominion		The legal entity, Dominion Resources, Inc., one or more of its consolidated subsidiaries (other than Virginia Power) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries

DRS		Dominion Resources Services, Inc.

DSM		Demand-side management

Dth		Dekatherm

DVP		Dominion Virginia Power operating segment

East Ohio		The East Ohio Gas Company, doing business as Dominion East Ohio

Elwood		Elwood power station

Enterprise		Enterprise Products Partners, L.P.

EPA		Environmental Protection Agency

EPS		Earnings per share

ERM		Enterprise Risk Management

Fairless		Fairless power station

FCM		Futures Commission Merchant

FERC		Federal Energy Regulatory Commission

Fowler Ridge		A wind-turbine facility joint venture between Dominion and BP Alternative Energy, Inc. in Benton County, Indiana

FTRs		Financial transmission rights

GAAP		U.S. generally accepted accounting principles

Gal		Gallon

PAGE 3


Abbreviation or Acronym		Definition
GHG		Greenhouse gas

Harrisonburg-to-Endless-Caverns line		Virginia Power project to construct a 20-mile 230 kilovolt line from the Harrisonburg substation to the Endless Caverns substation

Heating degree days		Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day

INPO		Institute of Nuclear Power Operations

ISO		Independent system operator

ISO-NE		ISO New England

Juniper		Juniper Capital L.P.

Kewaunee		Kewaunee nuclear power station

Kincaid		Kincaid power station

LNG		Liquefied natural gas

Manchester Street		Manchester Street power station

MATS		Utility Mercury and Air Toxics Standard Rule

MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations

MF Global		MF Global Inc.

Millstone		Millstone nuclear power station

MISO		Midwest Independent Transmission System Operators, Inc.

Moody’s		Moody’s Investors Service

MW		Megawatt

MWh		Megawatt hour

NCEMC		North Carolina Electric Membership Corporation

NedPower		A wind-turbine facility joint venture between Dominion and Shell WindEnergy Inc. in Grant County, West Virginia

NGLs		Natural gas liquids

North Anna		North Anna nuclear power station

North Carolina Commission		North Carolina Utilities Commission

NO _x		Nitrogen oxide

NPDES		National Pollutant Discharge Elimination System

NRC		Nuclear Regulatory Commission

NSPS		New Source Performance Standards

O&M		Operations and maintenance

ODEC		Old Dominion Electric Cooperative

OPEB		Other Postretirement Employee Benefits

PIPP		Percentage of Income Payment Plan

PJM		PJM Interconnection, LLC

ppb		Parts-per-billion

RCC		Replacement Capital Covenants

RGGI		Regional Greenhouse Gas Initiative

Rider A1		A rate adjustment clause to reduce anticipated over-collected fuel expense for the second half of 2012, effective November 1, 2012 to December 31, 2012

Rider T		A rate adjustment clause associated with the recovery of certain electric transmission-related expenditures

Rider T1		A rate adjustment clause to recover the difference between revenues produced from current Rider T rates included in base rates, and the new revenue requirement developed for the rate year beginning September 1, 2012

Riders C1A and C2A		Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in the 2011 DSM case

ROE		Return on equity

RTO		Regional transmission organization

Salem Harbor		Salem Harbor power station

SEC		Securities and Exchange Commission

September 2006 hybrids		2006 Series B Enhanced Junior Subordinated Notes due 2066

PAGE 4


Abbreviation or Acronym		Definition
SO ₂		Sulfur dioxide

Standard & Poor’s		Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.

State Line		State Line power station

Surry		Surry nuclear power station

U.S.		United States of America

UAO		Unilateral Administrative Order

VIE		Variable interest entity

Virginia Commission		Virginia State Corporation Commission

Virginia Power		The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power and its consolidated subsidiaries

PAGE 5

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011 ⁽¹⁾		2012			2011 ⁽¹⁾
(millions, except per share amounts)
Operating Revenue	$	3,411		$	3,745	$	9,926		$	11,016

Operating Expenses
Electric fuel and other energy-related purchases		1,052			1,217		2,893			3,195
Purchased electric capacity		86			109		297			344
Purchased gas		191			335		818			1,342
Other operations and maintenance		1,134			859		2,549			2,387
Depreciation, depletion and amortization		306			268		882			783
Other taxes		124			129		439			411

Total operating expenses		2,893			2,917		7,878			8,462

Income from operations		518			828		2,048			2,554

Other income		56			16		174			112
Interest and related charges		215			249		667			691

Income from continuing operations including noncontrolling interests before income tax expense		359			595		1,555			1,975
Income tax expense		139			203		552			730

Income from continuing operations including noncontrolling interests		220			392		1,003			1,245
Income (loss) from discontinued operations ⁽²⁾		(5	)		4		(22	)		(26	)

Net Income Including Noncontrolling Interests		215			396		981			1,219
Noncontrolling Interests		6			4		20			12

Net Income Attributable to Dominion	$	209		$	392	$	961		$	1,207

Amounts Attributable to Dominion:
Income from continuing operations, net of tax	$	214		$	388	$	983		$	1,233
Income (loss) from discontinued operations, net of tax		(5	)		4		(22	)		(26	)

Net income attributable to Dominion	$	209		$	392	$	961		$	1,207

Earnings Per Common Share-Basic
Income from continuing operations	$	0.37		$	0.68	$	1.72		$	2.15
Income (loss) from discontinued operations		(0.01	)		0.01		(0.04	)		(0.05	)

Net income attributable to Dominion	$	0.36		$	0.69	$	1.68		$	2.10

Earnings Per Common Share-Diluted
Income from continuing operations	$	0.37		$	0.68	$	1.72		$	2.14
Income (loss) from discontinued operations		(0.01	)		0.01		(0.04	)		(0.04	)

Net income attributable to Dominion	$	0.36		$	0.69	$	1.68		$	2.10

Dividends declared per common share	$	0.5275		$	0.4925	$	1.5825		$	1.4775

(1)	Dominion’s Consolidated Statements of Income for the three and nine months ended September 30, 2011 have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

(2)	Includes income tax benefit (expense) of $14 million and $(1) million for the three months ended September 30, 2012 and 2011, respectively, and $27 million and $8 million for the nine months ended September 30, 2012 and 2011, respectively.

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

PAGE 6

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
(millions)
Net income including noncontrolling interests	$	215		$	396		$	981		$	1,219
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities ⁽¹⁾		(86	)		(85	)		40			(159	)
Changes in unrealized net gains (losses) on investment securities ⁽²⁾		49			(101	)		110			(61	)
Changes in net unrecognized pension and other postretirement benefit costs ⁽³⁾		(6	)		—			(4	)		23
Amounts reclassified to net income:
Net derivative gains-hedging activities ⁽⁴⁾		(20	)		(9	)		(63	)		(13	)
Net realized (gains) losses on investment securities ⁽⁵⁾		(4	)		18			(18	)		12
Net pension and other postretirement benefit costs ⁽⁶⁾		15			7			38			29

Total other comprehensive income (loss)		(52	)		(170	)		103			(169	)

Comprehensive income including noncontrolling interests		163			226			1,084			1,050
Comprehensive income attributable to noncontrolling interests		6			4			20			12

Comprehensive income attributable to Dominion	$	157		$	222		$	1,064		$	1,038

(1)	Net of $57 million and $50 million tax for the three months ended September 30, 2012 and 2011, respectively, and net of $(28) million and $101 million tax for the nine months ended September 30, 2012 and 2011, respectively.

(2)	Net of $(33) million and $67 million tax for the three months ended September 30, 2012 and 2011, respectively, and net of $(73) million and $40 million tax for the nine months ended September 30, 2012 and 2011, respectively.

(3)	Net of $(7) million and $— tax for both the three months ended September 30, 2012 and 2011, and net of $(8) million and $(15) million tax for the nine months ended September 30, 2012 and 2011, respectively.

(4)	Net of $12 million and $6 million tax for the three months ended September 30, 2012 and 2011, respectively, and net of $39 million and $11 million tax for the nine months ended September 30, 2012 and 2011, respectively.

(5)	Net of $3 million and $(12) million tax for the three months ended September 30, 2012 and 2011, respectively, and net of $12 million and $(8) million tax for the nine months ended September 30, 2012 and 2011, respectively.

(6)	Net of $(6) million and $(7) million tax for the three months ended September 30, 2012 and 2011, respectively, and net of $(23) million and $(19) million tax for the nine months ended September 30, 2012 and 2011, respectively.

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

PAGE 7

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30, 2012			December 31, 2011 ⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	81		$	102
Customer receivables (less allowance for doubtful accounts of $28 and $29)		1,510			1,780
Other receivables (less allowance for doubtful accounts of $4 and $8)		169			255
Inventories		1,257			1,348
Derivative assets		514			705
Other		1,122			1,240

Total current assets		4,653			5,430

Investments
Nuclear decommissioning trust funds		3,322			2,999
Investment in equity method affiliates		538			553
Restricted cash equivalents		49			141
Other		269			292

Total investments		4,178			3,985

Property, Plant and Equipment
Property, plant and equipment		44,397			42,033
Property, plant and equipment, VIE		957			957
Accumulated depreciation, depletion and amortization		(13,831	)		(13,320	)

Total property, plant and equipment, net		31,523			29,670

Deferred Charges and Other Assets
Goodwill		3,141			3,141
Regulatory assets		1,306			1,382
Other		2,085			2,006

Total deferred charges and other assets		6,532			6,529

Total assets	$	46,886		$	45,614

(1)	Dominion’s Consolidated Balance Sheet at December 31, 2011 has been derived from the audited Consolidated Financial Statements at that date.

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

PAGE 8

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


	September 30, 2012			December 31, 2011 ⁽¹⁾
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	1,308		$	1,479
Securities due within one year, VIE		867			—
Short-term debt		1,382			1,814
Accounts payable		1,020			1,250
Derivative liabilities		499			951
Other		1,486			1,468

Total current liabilities		6,562			6,962

Long-Term Debt
Long-term debt		15,513			14,785
Long-term debt, VIE		—			890
Junior subordinated notes payable to affiliates		268			268
Enhanced junior subordinated notes		1,363			1,451

Total long-term debt		17,144			17,394

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		6,337			5,216
Asset retirement obligations		1,610			1,383
Regulatory liabilities		1,508			1,324
Other		1,590			1,575

Total deferred credits and other liabilities		11,045			9,498

Total liabilities		34,751			33,854

Commitments and Contingencies (see Note 15)
Subsidiary Preferred Stock Not Subject to Mandatory Redemption		257			257

Equity
Common stock – no par ⁽²⁾		5,420			5,180
Other paid-in capital		152			179
Retained earnings		6,753			6,697
Accumulated other comprehensive loss		(507	)		(610	)

Total common shareholders’ equity		11,818			11,446

Noncontrolling interest		60			57

Total equity		11,878			11,503

Total liabilities and equity	$	46,886		$	45,614

(1)	Dominion’s Consolidated Balance Sheet at December 31, 2011 has been derived from the audited Consolidated Financial Statements at that date.

(2)	1 billion shares authorized; 575 million shares and 570 million shares outstanding at September 30, 2012 and December 31, 2011, respectively.

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

PAGE 9

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)


Nine Months Ended September 30,	2012			2011
(millions)
Operating Activities
Net income including noncontrolling interests	$	981		$	1,219
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Impairment of merchant generation assets		444			55
Depreciation, depletion and amortization (including nuclear fuel)		1,080			951
Deferred income taxes and investment tax credits		550			643
Rate refunds		(132	)		(64	)
Other adjustments		(91	)		(96	)
Changes in:
Accounts receivable		371			527
Inventories		35			(162	)
Deferred fuel and purchased gas costs, net		332			(60	)
Prepayments		(72	)		(53	)
Accounts payable		(216	)		(419	)
Accrued interest, payroll and taxes		1			(201	)
Margin deposit assets and liabilities		126			(92	)
Other operating assets and liabilities		53			150

Net cash provided by operating activities		3,462			2,398

Investing Activities
Plant construction and other property additions (including nuclear fuel)		(2,884	)		(2,616	)
Proceeds from sales of securities		1,040			1,404
Purchases of securities		(1,047	)		(1,459	)
Restricted cash equivalents		92			196
Other		15			111

Net cash used in investing activities		(2,784	)		(2,364	)

Financing Activities
Repayment of short-term debt, net		(433	)		(602	)
Issuance and remarketing of long-term debt		1,500			2,245
Repayment of long-term debt		(1,037	)		(74	)
Issuance of common stock		197			37
Repurchase of common stock		—			(601	)
Common dividend payments		(906	)		(848	)
Subsidiary preferred dividend payments		(12	)		(12	)
Other		(8	)		(29	)

Net cash provided by (used in) financing activities		(699	)		116
Increase (decrease) in cash and cash equivalents		(21	)		150
Cash and cash equivalents at beginning of period		102			62

Cash and cash equivalents at end of period	$	81		$	212

Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	328		$	237

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

PAGE 10

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
(millions)
Operating Revenue	$	2,086	$	2,177	$	5,596	$	5,691

Operating Expenses
Electric fuel and other energy-related purchases		634		746		1,850		1,922
Purchased electric capacity		86		108		296		342
Other operations and maintenance:
Affiliated suppliers		91		79		256		229
Other		278		435		861		943
Depreciation and amortization		203		184		579		533
Other taxes		48		57		179		172

Total operating expenses		1,340		1,609		4,021		4,141

Income from operations		746		568		1,575		1,550

Other income		25		25		65		64
Interest and related charges		97		114		297		290

Income before income tax expense		674		479		1,343		1,324
Income tax expense		259		182		513		508

Net Income		415		297		830		816
Preferred dividends		4		4		12		12

Balance available for common stock	$	411	$	293	$	818	$	804

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

PAGE 11

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
(millions)
Net income	$	415		$	297		$	830		$	816
Other comprehensive income (loss), net of taxes:
Net deferred losses on derivatives-hedging activities ⁽¹⁾		(2	)		(3	)		(5	)		(3	)
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds ⁽²⁾		4			(10	)		11			(5	)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities ⁽³⁾		1			1			2			(2	)
Net realized (gains) losses on nuclear decommissioning trust funds ⁽⁴⁾		—			1			(1	)		1

Other comprehensive income (loss)		3			(11	)		7			(9	)

Comprehensive income	$	418		$	286		$	837		$	807

(1)	Net of $1 million and $3 million tax for the three months ended September 30, 2012 and 2011, respectively, and net of $3 million tax for both the nine months ended September 30, 2012 and 2011.

(2)	Net of $(4) million and $5 million tax for the three months ended September 30, 2012 and 2011, respectively, and net of $(7) million and $4 million tax for the nine months ended September 30, 2012 and 2011, respectively.

(3)	Net of $— million tax for both the three months ended September 30, 2012 and 2011, and net of $(2) million and $— million tax for the nine months ended September 30, 2012 and 2011, respectively.

(4)	Net of $— million and $(1) million tax for the three months ended September 30, 2012 and 2011, respectively, and net of $1 million and $— million tax for the nine months ended September 30, 2012 and 2011, respectively.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

PAGE 12

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30, 2012			December 31, 2011 ⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	21		$	29
Customer receivables (less allowance for doubtful accounts of $10 and $11)		930			892
Other receivables (less allowance for doubtful accounts of $3 and $7)		122			145
Inventories (average cost method)		757			797
Prepayments		28			41
Other		249			532

Total current assets		2,107			2,436

Investments
Nuclear decommissioning trust funds		1,506			1,370
Other		14			36

Total investments		1,520			1,406

Property, Plant and Equipment
Property, plant and equipment		29,942			28,626
Accumulated depreciation and amortization		(9,975	)		(9,615	)

Total property, plant and equipment, net		19,967			19,011

Deferred Charges and Other Assets
Intangible assets		178			183
Regulatory assets		350			399
Other		97			109

Total deferred charges and other assets		625			691

Total assets	$	24,219		$	23,544

(1)	Virginia Power’s Consolidated Balance Sheet at December 31, 2011 has been derived from the audited Consolidated Financial Statements at that date.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

PAGE 13

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


	September 30, 2012		December 31, 2011 ⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	1,042	$	616
Short-term debt		105		894
Accounts payable		410		405
Payables to affiliates		108		108
Affiliated current borrowings		187		187
Accrued interest, payroll and taxes		296		226
Other		475		685

Total current liabilities		2,623		3,121

Long-Term Debt		6,258		6,246

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		3,667		3,180
Asset retirement obligations		696		624
Regulatory liabilities		1,269		1,095
Other		252		271

Total deferred credits and other liabilities		5,884		5,170

Total liabilities		14,765		14,537

Commitments and Contingencies (see Note 15)
Preferred Stock Not Subject to Mandatory Redemption		257		257

Common Shareholder’s Equity

Common stock – no par ⁽²⁾		5,738		5,738
Other paid-in capital		1,112		1,111
Retained earnings		2,321		1,882
Accumulated other comprehensive income		26		19

Total common shareholder’s equity		9,197		8,750

Total liabilities and shareholder’s equity	$	24,219	$	23,544

(1)	Virginia Power’s Consolidated Balance Sheet at December 31, 2011 has been derived from the audited Consolidated Financial Statements at that date.

(2)	500,000 shares authorized; 274,723 shares outstanding at September 30, 2012 and December 31, 2011.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

PAGE 14

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


Nine Months Ended September 30,	2012			2011
(millions)
Operating Activities
Net income	$	830		$	816
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		687			625
Deferred income taxes and investment tax credits		331			449
Rate refunds		(132	)		(64	)
Other adjustments		(47	)		9
Changes in:
Accounts receivable		(2	)		14
Affiliated accounts receivable and payable		40			7
Inventories		40			(135	)
Deferred fuel expenses		321			(58	)
Accounts payable		28			6
Accrued interest, payroll and taxes		70			72
Other operating assets and liabilities		121			(44	)

Net cash provided by operating activities		2,287			1,697

Investing Activities
Plant construction and other property additions		(1,402	)		(1,392	)
Purchases of nuclear fuel		(142	)		(169	)
Purchases of securities		(491	)		(850	)
Proceeds from sales of securities		481			838
Restricted cash equivalents		21			131
Other		(18	)		11

Net cash used in investing activities		(1,551	)		(1,431	)

Financing Activities
Repayment of short-term debt, net		(789	)		(50	)
Issuance of affiliated current borrowings, net		—			112
Issuance and remarketing of long-term debt		450			160
Repayment of long-term debt		(10	)		(10	)
Common dividend payments		(379	)		(448	)
Preferred dividend payments		(12	)		(12	)
Other		(4	)		1

Net cash used in financing activities		(744	)		(247	)

Increase (decrease) in cash and cash equivalents		(8	)		19
Cash and cash equivalents at beginning of period		29			5

Cash and cash equivalents at end of period	$	21		$	24

Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	136		$	86

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

PAGE 15

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion’s operations are conducted through various subsidiaries, including Virginia Power, a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the SEC, Dominion’s and Virginia Power’s 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 Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011 and their Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012.

In Dominion’s and Virginia Power’s opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position as of September 30, 2012, their results of operations for the three and nine months ended September 30, 2012 and 2011 and their cash flows for the nine months ended September 30, 2012 and 2011. Such adjustments are normal and recurring in nature unless otherwise noted.

The Companies make certain estimates and assumptions in preparing their 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 revenues and expenses for the periods presented. Actual results may differ from those estimates.

Dominion’s and Virginia Power’s accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts and those of their respective majority-owned subsidiaries and those VIEs where Dominion has been determined to be the primary beneficiary.

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, rate changes, electric fuel and other energy-related purchases, purchased gas expenses and other factors.

Certain amounts in Dominion’s and Virginia Power’s 2011 Consolidated Financial Statements and Notes have been reclassified to conform to the 2012 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.

Note 3. Dispositions

In June 2012, Dominion entered into an agreement to sell Salem Harbor, which closed in the third quarter of 2012. In the second quarter of 2012, the assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell, resulting in a pre-tax charge of $27 million ($16 million after-tax), which is included in loss from discontinued operations in Dominion’s Consolidated Statements of Income. This was considered a Level 2 fair value measurement as it was based on the negotiated sales price.

During the second quarter of 2012, Dominion sold State Line, which ceased operations in March 2012.

The following table presents selected information regarding the results of operations of Salem Harbor and State Line, which are classified in discontinued operations in Dominion’s Consolidated Statements of Income for all periods presented:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
(millions)
Operating revenue	$	5		$	58	$	57		$	185
Income (loss) before income taxes		(19	)		5		(49	)		(34	)

PAGE 16

Note 4. Operating Revenue

The Companies’ operating revenue consists of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
(millions)
Dominion
Electric sales:
Regulated	$	2,046	$	2,136	$	5,495	$	5,594
Nonregulated		739		857		2,122		2,465
Gas sales:
Regulated		34		25		166		208
Nonregulated		177		281		740		1,220
Gas transportation and storage		297		291		1,007		1,151
Other		118		155		396		378

Total operating revenue	$	3,411	$	3,745	$	9,926	$	11,016

Virginia Power
Regulated electric sales	$	2,046	$	2,136	$	5,495	$	5,594
Other		40		41		101		97

Total operating revenue	$	2,086	$	2,177	$	5,596	$	5,691

Note 5. Income Taxes

Continuing Operations

For continuing operations, including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to Dominion’s and Virginia Power’s effective income tax rate as follows:


	Dominion						Virginia Power
Nine Months Ended September 30,	2012			2011			2012			2011
U.S. statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		5.0			3.6			3.9			3.9
AFUDC – equity		(1.1	)		(0.5	)		(0.8	)		(0.6	)
Employee stock ownership plan deduction		(0.8	)		(0.6	)		—			—
Production tax credits		(0.7	)		(0.5	)		—			—
Valuation allowances		(0.6	)		0.1			—			—
Other, net		(1.3	)		(0.2	)		0.1			0.1

Effective tax rate		35.5	%		36.9	%		38.2	%		38.4	%

Dominion’s effective tax rate in 2012 reflects a $20 million reduction of a valuation allowance related to state operating loss carryforwards attributable to Fairless. After considering the results of Fairless’ operations in recent years and a forecast of future operating results reflecting Dominion’s planned purchase of the facility, Dominion has concluded that it is more likely than not that the tax benefit of the operating losses will be realized. Significant assumptions include future commodity prices, in particular, those for electric energy produced by Fairless and those for natural gas, as compared to other fuels used for the generation of electricity, which will significantly influence the extent to which Fairless is dispatched by PJM. In addition, as disclosed in Note 15, in the third quarter of 2012, Dominion announced its intention to sell Brayton Point. Based on an evaluation of state tax credits previously recognized for Brayton Point, Dominion recorded an $11 million increase in valuation allowance related to credit carryforwards and a $14 million deferred tax liability, representing potential recapture of credits claimed in prior years. Dominion will continue to evaluate the likelihood of realizing these tax benefits on a quarterly basis.

As of September 30, 2012, there have been no material changes in Dominion’s and Virginia Power’s unrecognized tax benefits or possible changes that could reasonably be expected to occur during the next twelve months. See Note 6 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011 for a discussion of these unrecognized tax benefits.

PAGE 17

Discontinued Operations

Dominion’s effective tax rate for the nine months ended September 30, 2012 reflects the dispositions of State Line and Salem Harbor.

Dominion’s effective tax rate for the nine months ended September 30, 2011 reflects an expectation that State Line’s deferred tax assets, including 2011 operating losses, will not be realized in State Line’s separately filed state tax returns.

PAGE 18

Note 6. Earnings Per Share

The following table presents the calculation of Dominion’s basic and diluted EPS:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
(millions, except EPS)
Net income attributable to Dominion	$	209	$	392	$	961	$	1,207

Average shares of common stock outstanding – Basic		573.8		569.4		572.1		574.2
Net effect of potentially dilutive securities ⁽¹⁾		0.9		1.8		1.1		1.4

Average shares of common stock outstanding – Diluted		574.7		571.2		573.2		575.6

Earnings Per Common Share – Basic	$	0.36	$	0.69	$	1.68	$	2.10
Earnings Per Common Share – Diluted	$	0.36	$	0.69	$	1.68	$	2.10

(1)	Potentially dilutive securities consist of options, goal-based stock and contingently convertible senior notes.

There were no potentially dilutive securities excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2012 and 2011.

Note 7. Fair Value Measurements

Dominion’s and Virginia Power’s fair value measurements are made in accordance with the policies discussed in Note 7 to the Consolidated Financial Statements in their Annual Report on Form 10-K for the year ended December 31, 2011. See Note 8 in this report for further information about their derivatives and hedge accounting activities.

Dominion’s and Virginia Power’s commodity derivative valuations are prepared by the ERM department. The ERM department reports directly to the Companies’ CFO. The ERM department creates a daily file containing market valuations for the Companies’ derivative transactions. The inputs that go into the market valuations are transactional information stored in the systems of record and market pricing information that resides in data warehouses. The majority of forward prices are automatically uploaded into the data warehouses from various third-party sources. Inputs obtained from third-party sources are evaluated for reliability considering the reputation, independence, market presence, and methodology used by the third-party. If forward prices are not available from third-party sources, then the ERM department models the forward prices based on other available market data. A team consisting of risk management and risk quantitative analysts meets each business day to assess the validity of market prices and valuations. During this meeting, the changes in market valuations from period to period are examined and qualified against historical expectations. If any discrepancies are identified during this process, the mark-to-market valuations or the market pricing information is evaluated further and adjusted, if necessary.

Dominion and Virginia Power enter into certain physical and financial forwards and futures, options, and full requirements contracts, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards, futures, and full requirements contracts. An option model is used to value Level 3 physical and financial options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. Full requirements contracts add load shaping and usage factors in addition to the discounted cash flow model inputs. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, price correlations, the original sales prices, and volumes. For Level 3 fair value measurements, the forward market prices, the implied price volatilities, price correlations, load shaping, and usage factors are considered unobservable. The unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.

The following table presents Dominion’s quantitative information about Level 3 fair value measurements. Included are descriptions of the valuation techniques, the significant unobservable inputs, and the range of market price, price correlation and price volatility inputs used in the fair value measurements at September 30, 2012 for each category of transaction and commodity type. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility, price correlations, load shaping, and usage factors.

PAGE 19


	Fair Value (millions)		Valuation Techniques	Unobservable Input	Range			Weighted Average ⁽¹⁾

At September 30, 2012
Assets:
Physical and Financial Forwards and Futures:
Natural Gas ⁽²⁾	$	29	Discounted Cash Flow	Market Price (per Dth) ⁽³ ⁾		(1) - 6			3
Electricity		63	Discounted Cash Flow	Market Price (per MWh) ⁽³ ⁾		30 - 64			44
FTRs		6	Discounted Cash Flow	Market Price (per MWh) ⁽³ ⁾		(5) - 7			0
Capacity		8	Discounted Cash Flow	Market Price (per MW) ⁽³ ⁾		95 - 115			100
Liquids		29	Discounted Cash Flow	Market Price (per Gal) ⁽³ ⁾		0 - 3			1
Physical and Financial Options:
Natural Gas		4	Option Model	Market Price (per Dth) ⁽³ ⁾		0 - 5			4
				Price Volatility ⁽⁴ ⁾		20% - 53	%		25	%
				Price Correlation ⁽⁵ ⁾		73% - 99	%		77	%
Full Requirements Contracts:
Electricity		31	Discounted Cash Flow	Market Price (per MWh) ⁽³⁾		9 - 420			40
				Load Shaping ⁽⁶⁾		2% - 6	%		4	%
				Usage Factor ⁽⁷⁾		1% - 15	%		8	%

Total assets	$	170

Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas ⁽²⁾	$	19	Discounted Cash Flow	Market Price (per Dth) ⁽³ ⁾		(1) - 6			4
Electricity		13	Discounted Cash Flow	Market Price (per MWh) ⁽³ ⁾		27 - 64			43
FTRs		3	Discounted Cash Flow	Market Price (per MWh) ⁽³ ⁾		(2) - 10			1
Liquids ⁽⁸⁾		14	Discounted Cash Flow	Market Price (per Gal) ⁽³⁾		1 - 3			2
Physical and Financial Options:
Natural Gas ⁽²⁾		18	Option Model	Market Price (per Dth) ⁽³ ⁾		3 - 5			4
				Price Volatility ⁽⁴ ⁾		20% - 50	%		27	%
				Price Correlation ⁽⁵ ⁾		99	%		99	%

Total liabilities	$	67

(1)	Averages weighted by volume.

(2)	Includes basis.

(3)	Represents market prices beyond defined terms for Levels 1 & 2.

(4)	Represents volatilities unrepresented in published markets.

(5)	Represents intra-price correlations for which markets do not exist.

(6)	Converts block monthly loads to 24-hour load shapes.

(7)	Represents expected increase (decrease) in sales volumes compared to historical usage.

(8)	Includes NGLs and oil.

PAGE 20

Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:


Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market Price	Buy	Increase (decrease)	Gain (loss)
Market Price	Sell	Increase (decrease)	Loss (gain)
Price Volatility	Buy	Increase (decrease)	Gain (loss)
Price Volatility	Sell	Increase (decrease)	Loss (gain)
Price Correlation	Buy	Increase (decrease)	Loss (gain)
Price Correlation	Sell	Increase (decrease)	Gain (loss)
Load Factor	Sell ⁽¹⁾	Increase (decrease)	Loss (gain)
Usage Factor	Sell ⁽²⁾	Increase (decrease)	Gain (loss)

(1)	Assumes the contract is in a gain position and load increases during peak hours.

(2)	Assumes the contract is in a gain position.

Non-recurring Fair Value Measurements

In April 2011, Dominion announced it would pursue a sale of Kewaunee since it was not able to move forward with its original plan to grow its nuclear fleet in the Midwest to take advantage of economies of scale. Dominion has been unable to find a buyer for the facility. In addition, the power purchase agreements for the two utilities that contract to buy Kewaunee’s generation will expire in December 2013 at a time of projected low wholesale electricity prices in the region. At September 30, 2012, Dominion expected that it would permanently cease generation operations at Kewaunee in 2013 and commence decommissioning of the facility. As a result, Dominion evaluated Kewaunee for impairment since it was more likely than not that Kewaunee would be retired before the end of its previously estimated useful life. As management is not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of Kewaunee’s long-lived assets. This is considered a Level 3 fair value measurement due to the use of significant unobservable inputs including estimates of future power and other commodity prices.

As a result of this evaluation, Dominion recorded impairment and other charges of $435 million ($281 million after-tax) largely reflected in other O&M expense in its Consolidated Statement of Income for the three and nine months ended September 30, 2012. This primarily reflects a $378 million ($244 million after-tax) charge for the full impairment of Kewaunee’s long-lived assets, a write down of materials and supplies inventories of $33 million ($21 million after-tax), and a $24 million ($16 million after-tax) charge related to severance costs. In addition to these initial charges, Dominion anticipates recording additional charges related to the exit plan of approximately $50 million ($30 million after-tax). This primarily reflects expected cash expenditures for employee retention costs.

The decision to decommission Kewaunee was approved by Dominion’s BOD on October 18, 2012 after consideration of the factors discussed above, which made it uneconomic for Kewaunee to continue operations. Pending a grid reliability review by MISO, the station is expected to cease power production in the second quarter of 2013 and move to safe shutdown. Following station shutdown, Dominion plans to meet its obligations to the two utilities that purchase Kewaunee’s generation through market purchases, until the power purchase agreements expire in December 2013.

In the third quarter of 2011, Dominion and Virginia Power evaluated their SO ₂ emissions allowances not expected to be consumed by generating units for potential impairment due to the EPA’s issuance of CSAPR, as discussed in Note 15. Prior to the issuance of CSAPR, Dominion and Virginia Power held $57 million and $43 million, respectively, of SO ₂ emissions allowances obtained for ARP and CAIR compliance. Due to CSAPR’s establishment of a new allowance program and the elimination of CAIR, Dominion and Virginia Power had more SO ₂ emissions allowances than needed for ARP compliance. As a result of this evaluation, Dominion and Virginia Power recorded an impairment charge of $57 million ($34 million after-tax) and $43 million ($26 million after-tax), respectively, in other operations and maintenance expense in their Consolidated Statements of Income, to write down these emissions allowances to their estimated fair value of less than $1 million. To estimate the value of these emissions allowances, Dominion utilized a market approach by obtaining broker quotes to validate CSAPR’s impact on emissions allowance prices. However, due to limited market activity for future SO ₂ vintage year allowances, this was considered a Level 3 fair value measurement.

During March 2011, Dominion determined that it was unlikely that State Line would participate in the May 2011 PJM capacity base residual auction that would commit State Line’s capacity from June 2014 through May 2015. This determination reflected an expectation that margins for coal-fired generation will remain compressed in the 2014 and 2015 period in combination with the expectation that State Line may be impacted during the same time period by environmental regulations that would likely require significant capital expenditures. As a result, Dominion evaluated State Line for impairment since it was more likely than not that State Line would be retired before the end of its previously estimated useful life. As a result of this evaluation,

PAGE 21

Dominion recorded an impairment charge of $55 million ($39 million after-tax), which is now reflected in loss from discontinued operations in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of less than $1 million. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of State Line’s long-lived assets in the impairment test. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs including estimates of future power and other commodity prices. State Line was retired in March 2012 and sold in the second quarter of 2012. See Note 3 for further information.

See Note 3 for a non-recurring fair value measurement related to Salem Harbor.

PAGE 22

Recurring Fair Value Measurements

Dominion

The following table presents Dominion’s 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)
At September 30, 2012
Assets:
Derivatives:
Commodity	$	13	$	573	$	170	$	756
Interest rate		—		93		—		93
Investments ⁽¹⁾ :
Equity securities:
U.S.:
Large cap		1,967		—		—		1,967
Other		57		—		—		57
Non-U.S.:
Large cap		11		—		—		11
Fixed income:
Corporate debt instruments		—		318		—		318
U.S. Treasury securities and agency debentures		332		154		—		486
State and municipal		—		357		—		357
Other		—		11		—		11
Cash equivalents and other		1		74		—		75
Restricted cash equivalents		—		49		—		49

Total assets	$	2,381	$	1,629	$	170	$	4,180

Liabilities:
Derivatives:
Commodity	$	8	$	440	$	67	$	515
Interest rate		—		138		—		138

Total liabilities	$	8	$	578	$	67	$	653

At December 31, 2011
Assets:
Derivatives:
Commodity	$	44	$	828	$	93	$	965
Interest rate		—		105		—		105
Investments ⁽¹⁾ :
Equity securities:
U.S.:
Large cap		1,718		—		—		1,718
Other		51		—		—		51
Non-U.S.:
Large cap		10		—		—		10
Fixed income:
Corporate debt instruments		—		332		—		332
U.S. Treasury securities and agency debentures		277		181		—		458
State and municipal		—		329		—		329
Other		—		23		—		23
Cash equivalents and other		—		60		—		60
Restricted cash equivalents		—		141		—		141

Total assets	$	2,100	$	1,999	$	93	$	4,192

Liabilities:
Derivatives:
Commodity	$	10	$	714	$	164	$	888
Interest rate		—		269		—		269

Total liabilities	$	10	$	983	$	164	$	1,157

(1)	Includes investments held in the nuclear decommissioning and rabbi trusts.

PAGE 23

The following table presents the net change in Dominion’s 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,
	2012			2011			2012			2011
(millions)
Beginning balance	$	155		$	(122	)	$	(71	)	$	(50	)
Total realized and unrealized gains (losses):
Included in earnings		(8	)		(16	)		(31	)		(24	)
Included in other comprehensive income (loss)		(48	)		75			124			16
Included in regulatory assets/liabilities		2			(3	)		30			(35	)
Settlements		3			24			54			47
Transfers out of Level 3		(1	)		—			(3	)		4

Ending balance	$	103		$	(42	)	$	103		$	(42	)

The amount of gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date	$	(15	)	$	7		$	25		$	29

The following table presents Dominion’s classification of gains and losses included in earnings in the Level 3 fair value category:


	Operating revenue			Electric fuel and other energy-related purchases			Total
(millions)
Three Months Ended September 30, 2012
Total gains (losses) included in earnings	$	(10	)	$	2		$	(8	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		(15	)		—			(15	)

Three Months Ended September 30, 2011
Total gains (losses) included in earnings	$	(8	)	$	(8	)	$	(16	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		7			—			7

Nine Months Ended September 30, 2012
Total gains (losses) included in earnings	$	13		$	(44	)	$	(31	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		25			—			25

Nine Months Ended September 30, 2011
Total gains (losses) included in earnings	$	(8	)	$	(16	)	$	(24	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		29			—			29

PAGE 24

Virginia Power

The following table presents Virginia Power’s 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)
At September 30, 2012
Assets:
Derivatives:
Commodity	$	—	$	3	$	6	$	9
Investments ⁽¹⁾ :
Equity securities:
U.S.:
Large cap		775		—		—		775
Other		26		—		—		26
Fixed income:
Corporate debt instruments		—		194		—		194
U.S. Treasury securities and agency debentures		138		64		—		202
State and municipal		—		144		—		144
Other		—		7		—		7
Cash equivalents and other		—		30		—		30
Restricted cash equivalents		—		11		—		11

Total assets	$	939	$	453	$	6	$	1,398

Liabilities:
Derivatives:
Commodity	$	—	$	3	$	3	$	6
Interest rate		—		92		—		92

Total liabilities	$	—	$	95	$	3	$	98

At December 31, 2011
Assets:
Derivatives:
Commodity	$	—	$	—	$	2	$	2
Investments ⁽¹⁾ :
Equity securities:
U.S.:
Large cap		679		—		—		679
Other		23		—		—		23
Fixed income:
Corporate debt instruments		—		214		—		214
U.S. Treasury securities and agency debentures		107		63		—		170
State and municipal		—		125		—		125
Other		—		16		—		16
Cash equivalents and other		—		40		—		40
Restricted cash equivalents		—		32		—		32

Total assets	$	809	$	490	$	2	$	1,301

Liabilities:
Derivatives:
Commodity	$	—	$	17	$	30	$	47
Interest rate		—		100		—		100

Total liabilities	$	—	$	117	$	30	$	147

(1)	Includes investments held in the nuclear decommissioning and rabbi trusts.

PAGE 25

The following table presents the net change in Virginia Power’s 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,
	2012			2011			2012			2011
(millions)
Beginning balance	$	1		$	(18	)	$	(28	)	$	14
Total realized and unrealized gains (losses):
Included in earnings		2			(8	)		(44	)		(16	)
Included in regulatory assets/liabilities		2			(3	)		31			(35	)
Settlements		(2	)		8			44			16

Ending balance	$	3		$	(21	)	$	3		$	(21	)

The gains and losses included in earnings in the Level 3 fair value category were classified in electric fuel and other energy-related purchases in Virginia Power’s Consolidated Statements of Income for the three and nine months ended September 30, 2012 and 2011. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and nine months ended September 30, 2012 and 2011.

Fair Value of Financial Instruments

Substantially all of Dominion’s and Virginia Power’s 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 cash and cash equivalents, customer and other receivables, short-term debt and accounts payable are representative of fair value because of the short-term nature of these instruments. For Dominion’s and Virginia Power’s financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:


	September 30, 2012				December 31, 2011
	Carrying Amount		Estimated Fair Value ⁽¹⁾		Carrying Amount		Estimated Fair Value ⁽¹⁾
(millions)
Dominion
Long-term debt, including securities due within one year ⁽²⁾	$	16,821	$	19,952	$	16,264	$	18,936
Long-term debt, including securities due within one year, VIE ⁽³⁾		867		874		890		892
Junior subordinated notes payable to affiliates		268		271		268		268
Enhanced junior subordinated notes		1,363		1,451		1,451		1,518
Subsidiary preferred stock ⁽⁴⁾		257		262		257		256

Virginia Power
Long-term debt, including securities due within one year ⁽²⁾	$	7,300	$	8,900	$	6,862	$	8,281
Preferred stock ⁽⁴⁾		257		262		257		256

(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. All fair value measurements are classified as Level 2. 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)	Includes amounts which represent the unamortized discount and premium. At September 30, 2012 and December 31, 2011, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt of approximately $93 million and $105 million, respectively.

(3)	Includes amounts which represent the unamortized premium.

(4)	Includes deferred issuance expenses of $2 million at September 30, 2012 and December 31, 2011.

Note 8. Derivatives and Hedge Accounting Activities

Dominion’s and Virginia Power’s accounting policies and objectives and strategies for using derivative instruments are discussed in Note 2 to the Consolidated Financial Statements in their Annual Report on Form 10-K for the year ended December 31, 2011. See Note 7 in this report for further information about fair value measurements and associated valuation methods for derivatives.

PAGE 26

Dominion

The following table presents the volume of Dominion’s derivative activity as of September 30, 2012. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price ⁽¹⁾		253		74
Basis ⁽¹⁾		820		500
Electricity (MWh):
Fixed price ⁽¹⁾		21,889,805		15,308,096
FTRs		71,103,622		237,523
Capacity (MW)		100,425		207,460
Liquids (Gal) ⁽²⁾		140,658,000		168,210,000
Interest rate	$	1,900,000,000	$	2,340,000,000

(1)	Includes options.

(2)	Includes NGLs and oil.

For the three and nine months ended September 30, 2012 and 2011, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness 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.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at September 30, 2012:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(27	)	$	(23	)		27 months
Electricity		108			39			39 months
NGLs		9			3			27 months
Other		4			3			44 months
Interest rate		(171	)		(22	)		360 months

Total	$	(77	)	$	—

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

PAGE 27

Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of Dominion’s derivatives and where they are presented in its Consolidated Balance Sheets:


	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
September 30, 2012
ASSETS
Current Assets
Commodity	$	148	$	328	$	476
Interest rate		38		—		38

Total current derivative assets		186		328		514

Noncurrent Assets
Commodity		176		104		280
Interest rate		55		—		55

Total noncurrent derivative assets ⁽¹⁾		231		104		335

Total derivative assets	$	417	$	432	$	849

LIABILITIES
Current Liabilities
Commodity	$	81	$	290	$	371
Interest rate		99		29		128

Total current derivative liabilities		180		319		499

Noncurrent Liabilities
Commodity		65		79		144
Interest rate		3		7		10

Total noncurrent derivative liabilities ⁽²⁾		68		86		154

Total derivative liabilities	$	248	$	405	$	653

December 31, 2011
ASSETS
Current Assets
Commodity	$	176	$	495	$	671
Interest rate		34		—		34

Total current derivative assets		210		495		705

Noncurrent Assets
Commodity		198		96		294
Interest rate		71		—		71

Total noncurrent derivative assets ⁽¹⁾		269		96		365

Total derivative assets	$	479	$	591	$	1,070

LIABILITIES
Current Liabilities
Commodity	$	162	$	530	$	692
Interest rate		222		37		259

Total current derivative liabilities		384		567		951

Noncurrent Liabilities
Commodity		118		78		196
Interest rate		—		10		10

Total noncurrent derivative liabilities ⁽²⁾		118		88		206

Total derivative liabilities	$	502	$	655	$	1,157

(1)	Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheets.

(2)	Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheets.

PAGE 28

The following tables present the gains and losses on Dominion’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and 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, 2012
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	44
Purchased gas					(9	)
Electric fuel and other energy-related purchases					(4	)

Total commodity	$	(128	)		31		$	7

Interest rate ⁽³⁾		(15	)		1			(4	)

Total	$	(143	)	$	32		$	3

Three Months Ended September 30, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	28
Purchased gas					(7	)
Electric fuel and other energy-related purchases					2

Total commodity	$	69			23		$	(1	)

Interest rate ⁽³⁾		(204	)		(8	)		(76	)

Total	$	(135	)	$	15		$	(77	)

Nine Months Ended September 30, 2012
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	171
Purchased gas					(55	)
Electric fuel and other energy-related purchases					(16	)

Total commodity	$	159			100		$	14

Interest rate ⁽³⁾		(91	)		2			(44	)

Total	$	68		$	102		$	(30	)

Nine Months Ended September 30, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	88
Purchased gas					(61	)
Electric fuel and other energy-related purchases					4
Purchased electric capacity					1

Total commodity	$	(24	)		32		$	(10	)

Interest rate ⁽³⁾		(236	)		(8	)		(76	)

Total	$	(260	)	$	24		$	(86	)

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

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

PAGE 29


	Amount of Gain (Loss) Recognized in Income on Derivatives ⁽¹⁾
	Three Months Ended September 30,					Nine Months Ended September 30,
Derivatives not designated as hedging instruments	2012		2011			2012			2011
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	5	$	15		$	108		$	56
Purchased gas		3		(10	)		(2	)		(28	)
Electric fuel and other energy-related purchases		3		(8	)		(33	)		(16	)
Interest rate ⁽²⁾		10		(4	)		17			(4	)

Total	$	21	$	(7	)	$	90		$	8

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

(2)	Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges.

Virginia Power

The following table presents the volume of Virginia Power’s derivative activity as of September 30, 2012. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price		12		—
Basis		6		—
Electricity (MWh):
Fixed price		564,800		—
FTRs		69,715,081		—
Capacity (MW)		61,000		139,800
Interest rate	$	900,000,000	$	340,000,000

PAGE 30

Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:


	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not u nder Hedge Accounting		Total Fair Value
(millions)
September 30, 2012
ASSETS
Current Assets
Commodity	$	3	$	6	$	9

Total current derivative assets ⁽¹⁾		3		6		9

Total derivative assets	$	3	$	6	$	9

LIABILITIES
Current Liabilities
Commodity	$	1	$	4	$	5
Interest rate		54		29		83

Total current derivative liabilities ⁽²⁾		55		33		88

Noncurrent Liabilities
Commodity		1		—		1
Interest rate		2		7		9

Total noncurrent derivative liabilities ⁽³⁾		3		7		10

Total derivative liabilities	$	58	$	40	$	98

December 31, 2011
ASSETS
Current Assets
Commodity	$	—	$	2	$	2

Total current derivative assets ⁽¹⁾		—		2		2

Total derivative assets	$	—	$	2	$	2

LIABILITIES
Current Liabilities
Commodity	$	14	$	31	$	45
Interest rate		53		37		90

Total current derivative liabilities ⁽²⁾		67		68		135

Noncurrent Liabilities
Commodity		2		—		2
Interest rate		—		10		10

Total noncurrent derivative liabilities ⁽³⁾		2		10		12

Total derivative liabilities	$	69	$	78	$	147

(1)

Current derivative assets are presented in other current assets in Virginia Power’s Consolidated Balance Sheets.

(2)

Current derivative liabilities are presented in other current liabilities in Virginia Power’s Consolidated Balance Sheets.

(3)

Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheets.

PAGE 31

The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and 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, 2012
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)

Total commodity	$	—			(1	)	$	7

Interest rate ⁽³⁾		(3	)		—			(4	)

Total	$	(3	)	$	(1	)	$	3

Three Months Ended September 30, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)

Total commodity	$	(1	)		(1	)	$	(1	)

Interest rate ⁽³⁾		(5	)		—			(76	)

Total	$	(6	)	$	(1	)	$	(77	)

Nine Months Ended September 30, 2012
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(4	)

Total commodity	$	(1	)		(4	)	$	14

Interest rate ⁽³⁾		(7	)		—			(44	)

Total	$	(8	)	$	(4	)	$	(30	)

Nine Months Ended September 30, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Purchased electric capacity				$	1

Total commodity	$	(1	)		1		$	(10	)

Interest rate ⁽³⁾		(5	)		1			(76	)

Total	$	(6	)	$	2		$	(86	)

(1)	Amounts deferred into AOCI have no associated effect in Virginia Power’s 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 Virginia Power’s Consolidated Statements of Income.

(3)	Amounts are recorded in interest and related charges in Virginia Power’s Consolidated Statements of Income.

PAGE 32


	Amount of Gain (Loss) Recognized in Income on Derivatives ⁽¹⁾
	Three Months Ended September 30,					Nine Months Ended September 30,
Derivatives not designated as hedging instruments	2012		2011			2012			2011
(millions)
Derivative Type and Location of Gains (Losses)
Commodity ⁽²⁾	$	3	$	(8	)	$	(43	)	$	(16	)
Interest rate ⁽³⁾		1		(4	)		—			(4	)

Total	$	4	$	(12	)	$	(43	)	$	(20	)

(1)	Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.

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

(3)	Amounts are recorded in interest and related charges in Virginia Power’s Consolidated Statements of Income.

Note 9. Investments

Dominion

Equity and Debt Securities

Rabbi Trust Securities

Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled $90 million at September 30, 2012 and December 31, 2011. Cost method investments held in Dominion’s rabbi trusts totaled $15 million and $17 million at September 30, 2012 and December 31, 2011, respectively.

PAGE 33

Decommissioning Trust Securities

Dominion holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below.


	Amortized Cost		Total Unrealized Gains ⁽¹⁾		Total Unrealized Losses ⁽¹⁾			Fair Value
(millions)
September 30, 2012
Marketable equity securities:
U.S.:
Large Cap	$	1,182	$	755	$	—		$	1,937
Other		40		12		—			52
Marketable debt securities:
Corporate bonds		289		29		—			318
U.S. Treasury securities and agency debentures		463		22		(1	)		484
State and municipal		287		30		—			317
Other		10		1		—			11
Cost method investments		123		—		—			123
Cash equivalents and other ⁽²⁾		80		—		—			80

Total	$	2,474	$	849	$	(1	) ⁽³⁾	$	3,322

December 31, 2011
Marketable equity securities:
U.S.:
Large Cap	$	1,152	$	537	$	—		$	1,689
Other		36		10		—			46
Marketable debt securities:
Corporate bonds		314		19		(1	)		332
U.S. Treasury securities and agency debentures		437		20		(1	)		456
State and municipal		264		24		—			288
Other		23		1		—			24
Cost method investments		118		—		—			118
Cash equivalents and other ⁽²⁾		46		—		—			46

Total	$	2,390	$	611	$	(2	) ⁽³⁾	$	2,999

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

(2)	Includes pending sales of securities of $6 million and pending purchases of securities of $11 million at September 30, 2012 and December 31, 2011, respectively.

(3)	The fair value of securities in an unrealized loss position was $100 million and $164 million at September 30, 2012 and December 31, 2011, respectively.

PAGE 34

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2012 by contractual maturity is as follows:


	Amount
(millions)
Due in one year or less	$	108
Due after one year through five years		281
Due after five years through ten years		359
Due after ten years		382

Total	$	1,130

Presented below is selected information regarding Dominion’s marketable equity and debt securities held in nuclear decommissioning trust funds.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
(millions)
Proceeds from sales	$	276	$	465	$	1,040	$	1,404
Realized gains ⁽¹⁾		15		23		71		55
Realized losses ⁽¹⁾		6		62		25		82

(1)	Includes realized gains or losses recorded to the decommissioning trust regulatory liability.

Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
(millions)
Total other-than-temporary impairment losses ⁽¹⁾	$	6		$	54		$	20		$	69
Losses recorded to decommissioning trust regulatory liability		(3	)		(16	)		(8	)		(22	)
Losses recognized in other comprehensive income (before taxes)		—			(2	)		(1	)		(3	)

Net impairment losses recognized in earnings	$	3		$	36		$	11		$	44

(1)	Amount includes other-than-temporary impairment losses for debt securities of $1 million and $3 million for the three months ended September 30, 2012 and 2011, respectively, and $3 million and $5 million for the nine months ended September 30, 2012 and 2011, respectively.

PAGE 35

Virginia Power

Decommissioning Trust Securities

Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below.


	Amortized Cost		Total Unrealized Gains ⁽¹⁾		Total Unrealized Losses ⁽¹⁾			Fair Value
(millions)
September 30, 2012
Marketable equity securities:
U.S.:
Large Cap	$	467	$	307	$	—		$	774
Other		20		6		—			26
Marketable debt securities:
Corporate bonds		177		17		—			194
U.S. Treasury securities and agency debentures		197		6		(1	)		202
State and municipal		131		13		—			144
Other		7		—		—			7
Cost method investments		123		—		—			123
Cash equivalents and other ⁽²⁾		36		—		—			36

Total	$	1,158	$	349	$	(1	) ⁽³⁾	$	1,506

December 31, 2011
Marketable equity securities:
U.S.:
Large Cap	$	460	$	218	$	—		$	678
Other		18		5		—			23
Marketable debt securities:
Corporate bonds		204		11		(1	)		214
U.S. Treasury securities and agency debentures		166		4		—			170
State and municipal		114		10		—			124
Other		16		1		(1	)		16
Cost method investments		118		—		—			118
Cash equivalents and other ⁽²⁾		27		—		—			27

Total	$	1,123	$	249	$	(2	) ⁽³⁾	$	1,370

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

(2)	Includes pending sales of securities of $6 million and pending purchases of securities of $13 million at September 30, 2012 and December 31, 2011, respectively.

(3)	The fair value of securities in an unrealized loss position was $53 million and $99 million at September 30, 2012 and December 31, 2011, respectively.

The fair value of Virginia Power’s debt securities at September 30, 2012 by contractual maturity is as follows:


	Amount
(millions)
Due in one year or less	$	19
Due after one year through five years		145
Due after five years through ten years		213
Due after ten years		170

Total	$	547

PAGE 36

Presented below is selected information regarding Virginia Power’s marketable equity and debt securities.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
(millions)
Proceeds from sales	$	128	$	242	$	481	$	838
Realized gains ⁽¹⁾		6		10		27		21
Realized losses ⁽¹⁾		2		22		9		30

(1)	Includes realized gains or losses recorded to the decommissioning trust regulatory liability.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
(millions)
Total other-than-temporary impairment losses ⁽¹⁾	$	4		$	19		$	9		$	26
Losses recorded to decommissioning trust regulatory liability		(3	)		(16	)		(8	)		(22	)

Net impairment losses recognized in earnings	$	1		$	3		$	1		$	4

(1)	Amount includes other-than-temporary impairment losses for debt securities of $2 million for the three months ended September 30, 2011, and $2 million and $4 million for the nine months ended September 30, 2012 and 2011, respectively.

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Note 10. Regulatory Assets and Liabilities

Regulatory assets and liabilities include the following:


	September 30, 2012		December 31, 2011
(millions)
Dominion
Regulatory assets:
Deferred cost of fuel used in electric generation ⁽¹⁾	$	54	$	249
Deferred rate adjustment clause costs ⁽²⁾		50		113
Other		127		179

Regulatory assets-current ⁽³⁾		231		541

Unrecognized pension and OPEB costs ⁽⁴⁾		849		887
Income taxes recoverable through future rates ⁽⁵⁾		144		121
Derivatives ⁽⁶⁾		112		49
Deferred rate adjustment clause costs ⁽²⁾		85		72
Deferred cost of fuel used in electric generation ⁽¹⁾		—		122
Other		116		131

Regulatory assets-non-current		1,306		1,382

Total regulatory assets	$	1,537	$	1,923

Regulatory liabilities:
PIPP ⁽⁷⁾	$	82	$	58
Provision for rate proceedings ⁽⁸⁾		24		150
Other		42		35

Regulatory liabilities-current ⁽⁹⁾		148		243

Provision for future cost of removal and AROs ⁽¹⁰⁾		964		901
Decommissioning trust ⁽¹¹⁾		501		399
Other		43		24

Regulatory liabilities-non-current		1,508		1,324

Total regulatory liabilities	$	1,656	$	1,567

Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation ⁽¹⁾	$	54	$	249
Deferred rate adjustment clause costs ⁽²⁾		50		113
Other		64		117

Regulatory assets-current ⁽³⁾		168		479

Income taxes recoverable through future rates ⁽⁵⁾		115		100
Derivatives ⁽⁶⁾		112		49
Deferred rate adjustment clause costs ⁽²⁾		85		70
Deferred cost of fuel used in electric generation ⁽¹⁾		—		122
Other		38		58

Regulatory assets-non-current		350		399

Total regulatory assets	$	518	$	878

Regulatory liabilities:
Provision for rate proceedings ⁽⁸⁾	$	24	$	150
Other		40		28

Regulatory liabilities-current ⁽⁹⁾		64		178

Provision for future cost of removal ⁽¹⁰⁾		743		687
Decommissioning trust ⁽¹¹⁾		501		399
Other		25		9

Regulatory liabilities-non-current		1,269		1,095

Total regulatory liabilities	$	1,333	$	1,273

(1)	Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power’s generation operations. See Note 11 for more information.

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(2)	Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain riders. See Note 11 for more information.

(3)	Current regulatory assets are presented in other current assets in Dominion’s and Virginia Power’s Consolidated Balance Sheets.

(4)	Represents unrecognized pension and OPEB costs expected to be recovered through future rates by certain of Dominion’s rate-regulated subsidiaries.

(5)

Amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes.

(6)	For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

(7)

Under PIPP, eligible customers can receive energy assistance based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rider according to East Ohio tariff provisions. See Note 11 for more information.

(8)	Reflects a reserve associated with the settlement of Virginia Power’s 2009 base rate case proceedings and associated with the Biennial Review Order.

(9)	Current regulatory liabilities are presented in other current liabilities in Dominion’s and Virginia Power’s Consolidated Balance Sheets.

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

(11)

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 Virginia Power’s utility nuclear generation stations, in excess of the related ARO.

At September 30, 2012, approximately $285 million of Dominion’s and $219 million of Virginia Power’s regulatory assets represented past expenditures which do not currently earn a return. Dominion’s expenditures primarily include deferred cost of fuel used in electric generation. The above expenditures are expected to be recovered within the next two years.

Note 11. Regulatory Matters

Regulatory Matters Involving Potential Loss Contingencies

As a result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For matters for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on Dominion’s or Virginia Power’s financial position, liquidity or results of operations.

FERC - Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Dominion’s merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion’s market-based sales tariffs authorized by FERC. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in the wholesale market. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.

Rates

In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.

PAGE 39

In July 2008, Virginia Power filed an application with FERC requesting a revision to its revenue requirement to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 1.5% for four of the projects and an incentive of 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008. Ten of the eleven projects are expected to be completed by the end of 2012. The eleventh project was Virginia Power’s small portion of a larger transmission expansion which has been cancelled by PJM. Numerous parties sought rehearing of the FERC order in August 2008. In May 2012, FERC issued an order denying the rehearing requests. In July 2012, the North Carolina Commission filed an appeal of the FERC order with the U.S. Court of Appeals for the Fourth Circuit. While Virginia Power cannot predict the outcome of the appeal, it is not expected to have a material effect on results of operations.

In March 2010, ODEC and NCEMC filed a complaint with FERC against Virginia Power claiming that approximately $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. ODEC and NCEMC requested that FERC establish procedures to determine the amount of costs for each applicable project that should be excluded from Virginia Power’s rates. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. In February 2012, Virginia Power submitted to FERC a settlement agreement to resolve all issues set for hearing. All transmission customer parties to the proceeding joined the settlement. The Virginia Commission, North Carolina Commission and Public Staff of the North Carolina Commission, while not parties to the settlement, have agreed to not oppose the settlement. The settlement was accepted by FERC in May 2012 and provides for payment by Virginia Power to the transmission customer parties collectively of $250,000 per year for ten years and resolves all matters other than allocation of the incremental cost of certain underground transmission facilities, which has been briefed pursuant to FERC’s May 2012 order and awaits FERC action. While Virginia Power cannot predict the outcome of the briefing, it is not expected to have a material effect on results of operations.

PJM

In November 2011, PJM issued a formal notification that it would recalculate certain ancillary service revenues that had previously been paid during 2009, 2010 and 2011. Also in November 2011, PJM requested FERC permission to suspend its rebilling and repayment obligations associated with the recalculation of such revenues and petitioned FERC to establish a proceeding to determine the appropriate recalculations for the revenues during this period. In December 2011, FERC permitted the suspension of rebilling and repayment by PJM, subject to the outcome of FERC’s proceedings to determine the appropriate revenue recalculation. In April 2012, FERC issued an Order Establishing Hearing and Settlement Judge Procedures to address the appropriate recalculation of the ancillary service credits PJM will be required to collect from Virginia Power. As of September 30, 2012, Virginia Power has accrued $33 million for estimated future billing adjustments from PJM related to the ancillary service revenues. On August 16, 2012, PJM filed a settlement on behalf of itself, Virginia Power and the PJM Market Monitor. The settlement, if approved, will resolve all issues in the proceeding. PJM stated that all other participants to the proceeding either support or do not oppose the settlement.

Other Regulatory Matters

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 14 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011, Note 9 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 and Note 11 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012.

Virginia Regulation

Biennial Review

In September 2012, the Supreme Court of Virginia heard oral argument on Virginia Power’s appeals from the Biennial Review Order and the March 2012 Order denying Virginia Power’s petition seeking rehearing or reconsideration. The Supreme Court of Virginia is expected to issue its ruling in early November.

In September 2012, the Virginia Commission issued an Order for Notice and Hearing in the separate rulemaking proceeding to develop specific performance standards based on nationally recognized standards for the Virginia Commission’s consideration in determining positive or negative performance incentives for electric utilities. The Virginia Commission modified the proposed rules and regulations for performance incentives filed by the Staff of the Virginia Commission, allowed for further comments by November 2012 on the proposed rules and regulations as modified, and set a public hearing for November 2012. This case is pending.

Virginia Fuel Expenses

In September 2012, after a public hearing, the Virginia Commission issued an order approving Virginia Power’s application to decrease its annual fuel factor by approximately $389 million in fuel revenue for the rate year beginning July 1, 2012.

PAGE 40

Transmission Rider T1

In August 2012, the Virginia Commission approved Virginia Power’s proposed Rider T1 to recover costs of transmission service and demand response programs for the September 1, 2012 to August 31, 2013 rate year, ordering a Rider T1 reduction of approximately $100 million versus the Rider T customer rates currently in effect, and now combined in Virginia Power’s base rates. The Virginia Commission agreed with the approach recommended by Virginia Power and supported by the Staff of the Virginia Commission in this case. Rider T, which is now combined in base rates, along with Rider T1, will be tracked separately to permit deferral accounting and dollar-for-dollar recovery.

DSM Riders C1A and C2A

In August 2012, Virginia Power requested extension of two DSM programs (the Air Conditioner Cycling Program and the Low Income Program) by five years and two years, respectively, beyond their current April 30, 2013 termination date, as well as approval of a process whereby the Staff could administratively approve limited modifications to the designs of previously approved DSM programs. This case is pending.

Bremo Power Station

In August 2012, Virginia Power requested approval from the Virginia Commission of an amended and reissued certificate of public convenience and necessity that would allow Virginia Power to convert Bremo Units 3 and 4 from coal to natural gas as their fuel source. The proposed conversion would preserve 227 MW (net) of existing capacity. Cost recovery would occur through base rates, and not through a rate adjustment clause. This case is pending.

North Carolina Regulation

In August 2012, Virginia Power filed its annual fuel expense recovery application and testimony with the North Carolina Commission requesting a total annual fuel revenue decrease of approximately $27 million from the fuel and fuel-related costs currently in effect. Virginia Power’s filing also seeks to implement a voluntary rider, Rider A1, effective November 1, 2012 to December 31, 2012, to reduce projected over-collection of fuel expense in the second half of 2012.

In August 2012 and October 2012, Virginia Power filed supplemental testimony in the base rate proceeding which had the cumulative effect of updating Virginia Power’s requested overall base non-fuel revenue increase to $53 million. In September 2012, the North Carolina Commission staff filed testimony recommending a non-fuel revenue increase of $24 million. In October 2012, the North Carolina Commission issued a public notice stating that Virginia Power will begin billing under its proposed rates beginning November 1, 2012 on an interim basis, subject to refund with interest. A hearing was held in October 2012 and a decision by the North Carolina Commission is expected by the end of the year.

FERC Gas Regulation

Cove Point Rate Case

In May 2011, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective July 1, 2011. In June 2011, FERC accepted a July 1, 2011 effective date for all proposed rates but two, for which the effective date was suspended from July 1 to December 1, 2011. In April 2012, Cove Point filed a stipulation and agreement among Cove Point, FERC trial staff and the other active parties in the rate case resolving all issues set for hearing by FERC and establishing the mechanism for operational purchases of LNG. In July 2012, FERC issued an order approving the stipulation and agreement, including the settlement rates that are effective April 1, 2012. The settlement was considered final in early August 2012. Pursuant to the terms of the settlement, future operational purchases of LNG are not expected to affect Cove Point’s net results of operations. Cove Point and settling customers will be subject to a rate moratorium through December 31, 2016. Cove Point is required to file its next rate case in 2016 with rates to be effective January 1, 2017.

Note 12. Asset Retirement Obligations

AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of Dominion’s and Virginia Power’s long-lived assets. Dominion’s and Virginia Power’s AROs are primarily associated with the decommissioning of their nuclear generation facilities. In addition, Dominion’s AROs include plugging and abandonment of gas and oil wells, interim retirements of natural gas gathering, transmission, distribution and storage pipeline components, and the future abatement of asbestos expected to be disturbed in the Companies’ generation facilities.

The Companies have also identified, but not recognized, AROs related to retirement of Dominion’s LNG facility, Dominion’s gas storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in the Companies’ generation facilities.

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The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 2011 and 2012 were as follows:


	Amount
(millions)
Dominion
AROs at December 31, 2010 ⁽¹⁾	$	1,591
Obligations incurred during the period		16
Obligations settled during the period		(16	)
Revisions in estimated cash flows ⁽²⁾		(277	)
Accretion		84

AROs at December 31, 2011 ⁽¹⁾	$	1,398

Obligations incurred during the period		10
Obligations settled during the period		(10	)
Revisions in estimated cash flows ⁽³⁾		240
Accretion		56
Other		(10	)

AROs at September 30, 2012 ⁽¹⁾	$	1,684

Virginia Power
AROs at December 31, 2010 ⁽⁴⁾	$	672
Obligations incurred during the period		10
Obligations settled during the period		(3	)
Revisions in estimated cash flows ⁽²⁾		(90	)
Accretion		36

AROs at December 31, 2011 ⁽⁴⁾	$	625

Obligations incurred during the period		10
Obligations settled during the period		(1	)
Revisions in estimated cash flows		37
Accretion		25

AROs at September 30, 2012	$	696

(1)	Includes $14 million, $15 million and $74 million reported in other current liabilities at December 31, 2010, 2011, and September 30, 2012, respectively.

(2)	Primarily reflects the effect of lower anticipated costs due to the expected future recovery from the DOE of certain spent fuel storage costs.

(3)	Primarily reflects the accelerated timing of the decommissioning of Kewaunee to begin in 2013.

(4)	Includes $3 million and $1 million reported in other current liabilities at December 31, 2010 and 2011, respectively.

Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At September 30, 2012 and December 31, 2011, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $3.3 billion and $3.0 billion, respectively. At September 30, 2012 and December 31, 2011, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.5 billion and $1.4 billion, respectively.

Note 13. Variable Interest Entities

As discussed in Note 16 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011, certain variable pricing terms in some of the Companies’ long-term power and capacity contracts cause them to be considered variable interests in the counterparties.

PAGE 42

Virginia Power has long-term power and capacity contracts with four non-utility generators with an aggregate summer generation capacity of approximately 870 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $1.1 billion as of September 30, 2012. Virginia Power paid $52 million and $52 million for electric capacity and $27 million and $38 million for electric energy to these entities in the three months ended September 30, 2012 and 2011, respectively. Virginia Power paid $160 million and $156 million for electric capacity and $62 million and $103 million for electric energy to these entities in the nine months ended September 30, 2012 and 2011, respectively.

Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $86 million and $100 million for the three months ended September 30, 2012 and 2011, respectively, and $238 million and $292 million for the nine months ended September 30, 2012 and 2011, respectively. Virginia Power determined that it is 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 Virginia Power. Virginia Power has no obligation to absorb more than its allocated share of DRS costs.

See Note 16 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011 for additional information about consolidated VIEs.

Note 14. Significant Financing Transactions

Credit Facilities and Short-term Debt

Dominion and Virginia Power use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.

At September 30, 2012, Dominion’s commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:


	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility ⁽¹⁾	$	3,000	$	1,382	$	—	$	1,618
Joint revolving credit facility ⁽²⁾		500		—		23		477

Total	$	3,500	$	1,382	$	23	$	2,095

(1)	Effective September 2012, the maturity date was extended from September 2016 to September 2017. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.

(2)

Effective September 2012, the maturity date for $400 million of the $500 million in committed capacity of this credit facility was extended from September 2016 to September 2017. The remaining $100 million continues to have a maturity date of September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

Virginia Power’s short-term financing is supported by two joint revolving credit facilities with Dominion. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion and Virginia Power and for other general corporate purposes.

PAGE 43

At September 30, 2012, Virginia Power’s share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion were as follows:


	Facility Sub-limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility ⁽¹⁾	$	1,000	$	105	$	—	$	895
Joint revolving credit facility ⁽²⁾		250		—		2		248

Total	$	1,250	$	105	$	2	$	1,143

(1)

Effective September 2012, the maturity date for the credit facility was extended from September 2016 to September 2017. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.

(2)

In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility. Effective September 2012, the maturity date was extended from September 2016 to September 2017. This facility supports certain tax-exempt financings of Virginia Power.

Long-term Debt

In January 2012, Virginia Power issued $450 million of 2.95% senior notes that mature in 2022.

In September 2012, Dominion issued $350 million of 1.40% senior notes, $350 million of 2.75% senior notes and $350 million of 4.05% senior notes that mature in 2017, 2022 and 2042, respectively.

Convertible Securities

At September 30, 2012, Dominion had $82 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominion’s common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. The conversion rate is subject to adjustment upon certain events such as subdivisions, splits, combinations of common stock or the issuance to all common stock holders of certain common stock rights, warrants or options and certain dividend increases. As of September 30, 2012, the conversion rate has been adjusted, primarily due to individual dividend payments above the level paid at issuance, to 29.2650 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $34.17.

The senior notes are eligible for conversion during any calendar quarter when the closing price of Dominion’s common stock was equal to or higher than 120% of the conversion price for at least 20 out of the last 30 consecutive trading days of the preceding quarter. During the nine months ended September 30, 2012, the senior notes were eligible for conversion and approximately $61 million of the notes were converted by holders. The senior notes are eligible for conversion during the fourth quarter of 2012.

Enhanced Junior Subordinated Notes

In February 2012, Dominion launched a tender offer to purchase up to $150 million of the September 2006 hybrids. In the first quarter of 2012, Dominion purchased and canceled approximately $86 million of the September 2006 hybrids primarily as a result of this tender offer, which expired on March 23, 2012. In the second quarter of 2012, Dominion purchased and canceled approximately $2 million of the September 2006 hybrids. All purchases were conducted in compliance with the RCC.

From time to time, Dominion may reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity and repurchases in the open market, in privately negotiated transactions, through additional tender offers or otherwise.

Note 15. Commitments and Contingencies

As a result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in legal proceedings before various courts and are periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, and/or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For matters for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or

PAGE 44

investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on Dominion’s or Virginia Power’s financial position, liquidity or results of operations.

Environmental Matters

Air

The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of Dominion’s and Virginia Power’s facilities are subject to the CAA’s permitting and other requirements.

In December 2011, the EPA issued MATS for coal and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance will be required by April 16, 2015, with certain limited exceptions. Other than impacts disclosed in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011, the cost to comply with the rule is not expected to be material. Dominion continues to be governed by individual state mercury emission reduction regulations in Massachusetts and Illinois that are largely unaffected by this rule.

The EPA established CAIR with the intent to require significant reductions in SO ₂ and NO _X emissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO ₂ and NO _x emissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO ₂ and NO _x emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NO _x emissions caps, NO _x emissions caps during the ozone season (May 1 through September 30) and annual SO ₂ emission caps with differing requirements for two groups of affected states.

Following numerous petitions by industry participants for review and motions for stay, the U.S. Court of Appeals for the D.C. Circuit issued a ruling in December 2011 to stay CSAPR pending judicial review. In February and June 2012, the EPA issued technical revisions to CSAPR that are not material to Dominion. In August 2012, the Court vacated CSAPR in its entirety and ordered the EPA to implement CAIR until a valid replacement rule is issued. In October 2012, the EPA filed a petition requesting a rehearing of the court’s decision. The stay of CSAPR remains in effect and the EPA will continue to administer CAIR until such time that the EPA develops and implements new rulemaking addressing the issues identified by the Court. With respect to Dominion’s generation fleet, the cost to comply with CAIR is not expected to be material. Future outcomes of litigation and/or any additional action to issue a revised rule could affect the assessment regarding cost of compliance.

In May 2012, the EPA issued final designations for the 75-ppb ozone air quality standard. Several Dominion electric generating facilities are located in areas impacted by this standard. As part of the standard, states will be required to develop and implement plans to address sources emitting pollutants which contribute to the formation of ozone. Until the states have developed implementation plans, Dominion is unable to predict whether or to what extent the new rules will ultimately require additional controls.

In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, NSPS, the Title V permit program and the stations’ respective State Implementation Plans. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the CAA.

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Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The CAA authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. In addition to any such penalties that may be awarded, an adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures. Dominion is currently in settlement discussions to resolve these matters. There can be no assurance that Dominion will reach a settlement with the EPA. However, in the past, the EPA has settled similar claims with other energy companies requiring them to pay civil penalties and/or undertake mitigation projects. Dominion has accrued a liability of $13 million, which represents its best estimate of the probable loss related to civil penalties and mitigation projects in this matter, assuming Dominion is able to reach settlement with the EPA and based on the EPA’s settlement of similar claims with other energy companies. Dominion does not believe that final resolution of the matter will have a material adverse effect on its results of operations, financial condition or cash flows.

Water

The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. Dominion and Virginia Power must comply with all aspects of the CWA programs at their operating facilities.

In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. As of the end of the third quarter of 2012, the station was fully converted to closed cycle cooling. The total cost to install these cooling towers is approximately $550 million.

In September 2010, Millstone’s NPDES permit was reissued under the CWA. The conditions of the permit require an evaluation of control technologies that could result in additional expenditures in the future. The report summarizing the results of the evaluation was submitted in August 2012 and is under review by the Connecticut Department of Energy and Environmental Protection. Dominion cannot currently predict the outcome of this review. In October 2010, the permit issuance was appealed to the state court by a private plaintiff. The permit is expected to remain in effect during the appeal. Dominion is currently unable to make an estimate of the potential financial statement impacts related to this matter.

Solid and Hazardous Waste

The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be strictly, jointly and severally liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.

From time to time, Dominion or Virginia Power may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion or Virginia Power may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. Except as noted below, the Companies do not believe this will have a material effect on results of operations, financial condition and/or cash flows.

In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. In November 2011, Virginia Power and a number of other parties notified the EPA that they are declining to undertake the work set forth in the UAO.

The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO. Virginia Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter.

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Dominion has determined that it is associated with 17 former manufactured gas plant sites. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the 17 former sites with which Dominion is associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Dominion is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options, but is not yet able to estimate the future remediation costs. Due to the uncertainty surrounding these sites, Dominion is unable to make an estimate of the potential financial statement impacts related to these sites.

Climate Change Legislation and Regulation

Massachusetts, Rhode Island and Connecticut, among other states, have joined RGGI, a multi-state effort to reduce CO ₂ emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO ₂ emissions from power plants in participating states are required to be stabilized at current levels from 2009 to 2015. Further reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO ₂ emissions. During 2012, RGGI is undergoing a program review which could impact regulations and implementation of RGGI. The impact of this program review on Dominion’s fossil fired generation operations in RGGI states is unknown at this time, and Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.

Two of Dominion’s facilities, Brayton Point and Manchester Street, are subject to RGGI. Beginning with calendar year 2009, RGGI requires that Dominion cover each ton of CO ₂ direct stack emissions from these facilities with either an allowance or an offset. The allowances can be purchased through auction or through a secondary market. Dominion has periodically participated in RGGI allowance auctions to date and has procured allowances to meet its estimated compliance requirements under RGGI’s current requirement for 2012 through 2013 and most of 2014, therefore Dominion does not expect compliance with RGGI to have a material impact on its results of operations or financial condition. During June 2011, a lawsuit was filed in New York seeking to retroactively rescind RGGI participation by that state. A percentage of Dominion’s RGGI allowances had been acquired from New York. The allocated value of these allowances totaled approximately $38 million, of which all have been expensed as consumed for RGGI Phase I compliance. In February 2012, Dominion surrendered these New York RGGI allowances for the RGGI Phase I compliance period and therefore does not expect any significant financial statement impacts from this lawsuit as it no longer holds allowances issued by the state of New York. In June 2012, a New York state court dismissed the lawsuit. An appeal was filed in July 2012.

MF Global

Prior to October 31, 2011, certain of Dominion’s subsidiaries executed certain commodity transactions on exchanges using MF Global, an FCM registered with the CFTC. In order to secure its potential exposure on these commodity transactions, Dominion posted certain required margin collateral with MF Global. The parent company of MF Global, MF Global Holdings Ltd., filed for bankruptcy relief under Chapter 11 of the U.S. Bankruptcy Code on October 31, 2011. On the same date, the U.S. District Court for the Southern District of New York appointed a trustee to oversee the liquidation of MF Global pursuant to the Securities Investor Protection Act.

In accordance with court-approved procedures, Dominion transferred to other FCMs all open positions executed using MF Global. The initial margin posted for these open positions at October 31, 2011 was approximately $73 million. Dominion has received approximately $17 million of this amount through the liquidation process to date.

At this time, the MF Global trustee is determining the final amounts that will be recoverable and ultimately distributed to MF Global’s customers. As part of this process, the trustee has filed claims in the insolvency proceeding of MF Global affiliates in various foreign jurisdictions, including the United Kingdom, which claims are still pending. Due to the uncertainty surrounding the ultimate recovery on the claims filed by the MF Global trustee in the United Kingdom and elsewhere, the uncertain timing of such recovery, and the potential dilution of such recovered funds in the liquidation process, Dominion is unable to estimate the loss, if any, associated with its remaining margin claims or when it will receive any additional recoveries on such claims.

Nuclear Matters

In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as INPO. Like other U.S. nuclear operators, Dominion has been gathering supporting data and participating in industry initiatives focused on the ability to respond to and mitigate the consequences of design-basis and beyond-design-basis events at its stations.

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In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3, with the Tier 1 recommendations consisting of actions which the staff determined should be started without unnecessary delay. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations; and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.

Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion require implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation. The orders require prompt implementation of the safety enhancements and completion of implementation within two refueling outages or by December 31, 2016, whichever comes first. The information requests issued by the NRC request each reactor to reevaluate the seismic and flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. Dominion and Virginia Power do not currently expect that compliance with the NRC’s March 2012 orders and information requests will materially impact their financial position, results of operations or cash flows during the approximately four-year implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion and Virginia Power are currently unable to estimate the potential financial impacts related to compliance with Tier 2 and Tier 3 recommendations.

Guarantees

Dominion

At September 30, 2012, Dominion had issued $92 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of September 30, 2012, Dominion’s exposure under these guarantees was $62 million, primarily related to certain reserve requirements associated with non-recourse financing.

Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion’s consolidated subsidiaries, that liability is included in its Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.

At September 30, 2012, Dominion had issued the following subsidiary guarantees:


	Stated Limit		Value ⁽¹⁾
(millions)
Subsidiary debt ⁽²⁾	$	363	$	363
Commodity transactions ⁽³⁾		2,853		331
Nuclear obligations ⁽⁴⁾		231		57
Other ⁽⁵⁾		567		112

Total	$	4,014	$	863

(1)

Represents the estimated portion of the guarantee’s stated limit that is utilized as of September 30, 2012 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount.

(2)	Guarantees of debt of certain DEI subsidiaries. In the event of default by the subsidiaries, Dominion would be obligated to repay such amounts.

(3)

Guarantees related to energy trading and marketing activities and other commodity commitments of certain subsidiaries, including subsidiaries of Virginia Power and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion would be obligated to satisfy such obligation. Dominion and its subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits.

(4)

Guarantees related to certain DEI subsidiaries’ potential retrospective premiums that could be assessed if there is a nuclear incident under Dominion’s nuclear insurance programs and guarantees for a DEI subsidiary’s and Virginia Power’s commitment to buy nuclear fuel. Excludes Dominion’s agreement to provide up to $150 million and $60 million to two DEI subsidiaries to pay the operating expenses of Millstone and Kewaunee, respectively, in the event of a prolonged outage, as part of satisfying certain NRC requirements concerned with ensuring adequate funding for the operations of nuclear power stations.

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(5)

Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower.

Surety Bonds and Letters of Credit

As of September 30, 2012, Dominion had purchased $168 million of surety bonds, including $72 million at Virginia Power, and authorized the issuance of standby letters of credit by financial institutions of $23 million, including $2 million at Virginia Power, to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of the surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

Merchant Generation Operations

Dominion continually reviews its portfolio of assets to determine which assets fit strategically and support its objectives to improve return on invested capital and shareholder value. In connection with this effort, in the third quarter of 2012, Dominion decided to pursue the sale of Brayton Point and Kincaid. Since Dominion is unlikely to operate these merchant generation facilities through their estimated useful lives, this could result in an impairment of part or all of the carrying value of these power stations. In preparing its third quarter 2012 financial statements, Dominion evaluated these power stations for recoverability under a probability weighted approach and concluded that the carrying values of these facilities are not impaired as of September 30, 2012. In addition, in the third quarter of 2012 along with the proposed sale of Brayton Point and Kincaid, Dominion decided to pursue the sale of its interest in Elwood. Elwood is an equity method investment in which Dominion owns 50%. Certain events, including an offer to purchase for an amount less than the cost of the investment, could result in the recording of an other-than-temporary impairment charge. As of September 30, 2012, the net carrying value of these power stations and Dominion’s interest in Elwood is $2.0 billion.

Any sale of Brayton Point, Kincaid, or Dominion’s interest in Elwood would be subject to the approval of Dominion’s BOD, as well as applicable state and federal approvals.

Nuclear Operations

Spent Nuclear Fuel

Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Companies’ contracts with the DOE. The Companies have previously received damages award payments and settlement payments related to these contracts.

Dominion has resolved additional claims for damages incurred at Millstone and Kewaunee. In May 2012, Dominion made formal offers of settlement to the Authorized Representative of the Attorney General for resolution of claims incurred at Millstone for the period July 1, 2006 through December 31, 2010 and periodic payments after that date, and for resolution of claims incurred at Kewaunee for the period January 1, 2009 through December 31, 2010 and periodic payments after that date. In September 2012, Dominion and the government entered into settlement agreements. Initial settlement payments in the amounts of $20 million for Millstone and $6 million for Kewaunee were received in the fourth quarter of 2012. Virginia Power is seeking to resolve additional claims for damages incurred at Surry and North Anna after June 30, 2006. In September 2012, Virginia Power made a formal offer of settlement for resolution of claims incurred at Surry and North Anna for the period July 1, 2006 through December 31, 2010 and periodic payments after that date. This offer has not yet been formally accepted by the government and will not be effective until such formal acceptance is received. Virginia Power believes it is probable that its offer will be accepted by the government. In June 2012, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims for Millstone, Surry and North Anna against the DOE requesting additional damages for the period July 1, 2006 through December 31, 2010. The lawsuit for Millstone has been dismissed.

Dominion recognizes receivables for certain spent nuclear fuel-related costs that it believes are probable of recovery from the DOE. At September 30, 2012, Dominion’s and Virginia Power’s receivables for spent nuclear fuel-related costs totaled $145 million and $108 million, respectively.

Dominion will continue to manage its spent fuel until it is accepted by the DOE.

Note 16. Credit Risk

Dominion’s and Virginia Power’s accounting policies for credit risk are discussed in Note 24 to the Consolidated Financial Statements in their Annual Report on Form 10-K for the year ended December 31, 2011.

At September 30, 2012, Dominion’s gross credit exposure totaled $529 million. After the application of collateral, credit exposure was reduced to $524 million. Of this amount, investment grade counterparties, including those internally rated, represented 81%. One counterparty exposure represented 11% of Dominion’s total exposure and is a utility holding company rated investment grade. At September 30, 2012, Virginia Power’s exposure to potential concentrations of credit risk was not considered material.

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Credit-Related Contingent Provisions

The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit rating 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, 2012 and December 31, 2011, Dominion would have been required to post an additional $31 million and $88 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted 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. Dominion had posted $5 million in collateral, including $4 million of letters of credit, at September 30, 2012 and $110 million in collateral, including $4 million of letters of credit, at December 31, 2011, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. 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, 2012 and December 31, 2011 was $144 million and $259 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power were not material as of September 30, 2012 and December 31, 2011. See Note 8 for further information about derivative instruments.

Note 17. Related Party Transactions

Virginia Power engages in related-party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s 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. Virginia Power is included in Dominion’s consolidated federal income tax return and participates in certain Dominion benefit plans. A discussion of significant related party transactions follows.

Transactions with Affiliates

Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps, to manage commodity price risk associated with purchases of natural gas.

DRS and affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power.

Presented below are significant transactions with DRS and other affiliates:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
(millions)
Commodity purchases from affiliates	$	129	$	150	$	285	$	302
Services provided by affiliates		107		101		298		294

Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. Virginia Power’s outstanding borrowings, net of repayments, under the Dominion money pool for its nonregulated subsidiaries totaled $187 million as of both September 30, 2012 and December 31, 2011. There were no short-term demand note borrowings from Dominion as of September 30, 2012 and December 31, 2011. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the three and nine months ended September 30, 2012 and 2011, respectively.

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Note 18. Employee Benefit Plans

The components of Dominion’s provision for net periodic benefit cost were as follows:


	Pension Benefits						OPEB
	2012			2011			2012			2011
(millions)
Three Months Ended September 30,
Service cost	$	29		$	27		$	11		$	12
Interest cost		67			65			20			24
Expected return on plan assets		(108	)		(110	)		(19	)		(21	)
Amortization of prior service credit		—			—			(4	)		(3	)
Amortization of net loss		33			24			2			3
Settlements and curtailments ⁽¹⁾		—			—			(4	)		—

Net periodic benefit cost	$	21		$	6		$	6		$	15

Nine Months Ended September 30,
Service cost	$	87		$	81		$	33		$	36
Interest cost		201			194			60			71
Expected return on plan assets		(323	)		(331	)		(60	)		(60	)
Amortization of prior service cost (credit)		2			2			(10	)		(10	)
Amortization of net loss		99			72			5			9
Settlements and curtailments ⁽¹⁾		—			—			(4	)		(1	)

Net periodic benefit cost	$	66		$	18		$	24		$	45

(1)	2012 amount relates to the sale of Salem Harbor.

Employer Contributions

During the nine months ended September 30, 2012, Dominion made no contributions to its defined benefit pension plans or OPEB plans. Dominion expects to contribute approximately $16 million to its OPEB plans through Voluntary Employees’ Beneficiary Associations during the remainder of 2012.

Note 19. Operating Segments

Dominion and Virginia Power are organized primarily on the basis of products and services sold in the U.S. A description of the operations included in the Companies’ primary operating segments is as follows:


Primary Operating Segment	Description of Operations	Dominion	Virginia Power
DVP	Regulated electric distribution	X	X
	Regulated electric transmission	X	X
	Nonregulated retail energy marketing (electric and gas)	X
Dominion Generation	Regulated electric fleet	X	X
	Merchant electric fleet	X
Dominion Energy	Gas transmission and storage	X
	Gas distribution and storage	X
	LNG import and storage	X
	Producer services	X

In addition to the operating segments above, the Companies also report a Corporate and Other segment.

The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and certain specific items that are not included in profit measures evaluated by executive management in assessing segment performance or allocating resources among the segments.

In the nine months ended September 30, 2012, Dominion reported an after-tax net expense of $388 million for specific items in the Corporate and Other segment, with $397 million of these net expenses attributable to its operating segments. In the nine months ended September 30, 2011, Dominion reported after-tax net expenses of $179 million for specific items in the Corporate and Other segment, with $183 million of these net expenses attributable to its operating segments.

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The net expenses for specific items in 2012 primarily related to the impact of the following items:

•

A $458 million ($297 million after-tax) net loss, including impairment charges, primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013, attributable to Dominion Generation;

•

A $69 million ($42 million after-tax) charge reflecting restoration costs associated with damage caused by late June summer storms, attributable to DVP;

•

A $34 million ($45 million after-tax) net loss from operations of Brayton Point, Kincaid and Elwood, attributable to Dominion Generation, including $25 million of additional tax expense for the potential loss or recapture of state tax credits. Dominion announced its intention to pursue the sale of these three merchant power stations in the third quarter of 2012; and

•

A $49 million ($22 million after-tax) loss from discontinued operations of State Line and Salem Harbor which were sold in 2012, attributable to Dominion Generation.

The net expenses for specific items in 2011 primarily related to the impact of the following items:

•

A $121 million ($74 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP;

•

A $34 million ($26 million after-tax) loss from discontinued operations of State Line and Salem Harbor which were sold in 2012, attributable to Dominion Generation;

•

A $57 million ($34 million after-tax) charge related to the impairment of SO ₂ emissions allowances not expected to be consumed following the issuance of CSAPR in the third quarter of 2011, attributable to Dominion Generation; and

•

A $56 million ($32 million after-tax) loss from the operations of Kewaunee, attributable to Dominion Generation.

The Corporate and Other Segment of Virginia Power primarily includes certain specific items that are not included in profit measures evaluated by executive management in assessing segment performance or allocating resources among the segments. In the nine months ended September 30, 2012, Virginia Power reported an after-tax expense of $41 million for specific items attributable to its operating segments in the Corporate and Other segment. In the nine months ended September 30, 2011, Virginia Power reported after-tax net expenses of $126 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2012 primarily related to the impact of a $69 million ($42 million after-tax) charge reflecting restoration costs associated with damage caused by late June summer storms, attributable to DVP.

The net expenses for specific items in 2011 primarily related to the impact of the following items:

•

A $121 million ($74 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP; and

•

A $43 million ($26 million after-tax) charge related to the impairment of SO ₂ emissions allowances not expected to be consumed following the issuance of CSAPR in the third quarter of 2011, attributable to Dominion Generation.

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The following table presents segment information pertaining to Dominion’s operations:


	DVP		Dominion Generation ⁽¹⁾		Dominion Energy		Corporate andOther ⁽¹⁾			Adjustments/ Eliminations			Consolidated Total
(millions)
Three Months Ended September 30,
2012
Total revenue from external customers	$	836	$	1,821	$	291	$	119		$	344		$	3,411
Intersegment revenue		6		110		281		164			(561	)		—

Total operating revenue		842		1,931		572		283			(217	)		3,411
Loss from discontinued operations		—		—		—		(5	)		—			(5	)
Net income (loss) attributable to Dominion		119		363		104		(377	)		—			209

2011
Total revenue from external customers	$	922	$	2,083	$	290	$	24		$	426		$	3,745
Intersegment revenue		21		114		341		149			(625	)		—

Total operating revenue		943		2,197		631		173			(199	)		3,745
Income from discontinued operations		—		—		—		4			—			4
Net income (loss) attributable to Dominion		125		380		95		(208	)		—			392

Nine Months Ended September 30,
2012
Total revenue from external customers	$	2,573	$	5,070	$	1,278	$	191		$	814		$	9,926
Intersegment revenue		81		275		701		459			(1,516	)		—

Total operating revenue		2,654		5,345		1,979		650			(702	)		9,926
Loss from discontinued operations		—		—		—		(22	)		—			(22	)
Net income (loss) attributable to Dominion		428		737		362		(566	)		—			961

2011
Total revenue from external customers	$	2,801	$	5,578	$	1,503	$	98		$	1,036		$	11,016
Intersegment revenue		134		271		843		443			(1,691	)		—

Total operating revenue		2,935		5,849		2,346		541			(655	)		11,016
Loss from discontinued operations		—		—		—		(26	)		—			(26	)
Net income (loss) attributable to Dominion		389		852		368		(402	)		—			1,207

(1)	Dominion’s segment information for the three and nine months ended September 30, 2011 has been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

Intersegment sales and transfers for Dominion are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation.

The following table presents segment information pertaining to Virginia Power’s operations:


	DVP		Dominion Generation		Corporate and Other			Consolidated Total
(millions)
Three Months Ended September 30,
2012
Operating revenue	$	505	$	1,581	$	—		$	2,086
Net income		128		283		4			415

2011
Operating revenue	$	484	$	1,704	$	(11	)	$	2,177
Net income (loss)		127		289		(119	)		297

Nine Months Ended September 30,
2012
Operating revenue	$	1,413	$	4,183	$	—		$	5,596
Net income (loss)		335		534		(39	)		830

2011
Operating revenue	$	1,367	$	4,336	$	(12	)	$	5,691
Net income (loss)		342		598		(124	)		816

PAGE 53

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MD&A discusses Dominion’s and Virginia Power’s results of operations and general financial condition. MD&A should be read in conjunction with the Companies’ Consolidated Financial Statements.

Contents of MD&A

MD&A consists of the following information:

•

Forward-Looking Statements

•

Accounting Matters

•

Dominion

•

Results of Operations

•

Segment Results of Operations

•

Virginia Power

•

Results of Operations

•

Segment Results of Operations

•

Selected Information - Energy Trading Activities

•

Liquidity and Capital Resources

•

Future Issues and Other Matters

Forward-Looking Statements

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

Dominion and Virginia Power 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 and other natural disasters, including hurricanes, high winds, severe storms, and earthquakes that can cause outages and property damage to 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 GHGs 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, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;

•

Unplanned outages of the Companies’ facilities;

•

Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Dominion’s and Virginia Power’s liquidity position and the underlying value of their assets;

•

Counterparty credit and performance risk;

•

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

•

Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;

•

Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion;

•

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;

•

Risks of operating businesses in regulated industries that are subject to changing regulatory structures;

•

Impacts of decisions to acquire, divest or retire assets based on asset portfolio reviews; and receipt of approvals for, and timing of, closing dates for these or other transactions;

•

Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs and new and evolving capacity models;

PAGE 54

•

Political and economic conditions, including inflation and deflation;

•

Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;

•

Industrial, commercial and residential growth or decline in the Companies’ service areas and changes in customer growth or usage patterns, including as a result of energy conservation programs;

•

Additional competition in the electric industry, including in electric markets in which Dominion’s merchant generation facilities operate, and potential competition in the construction and ownership of electric transmission facilities in Virginia Power’s service territory, in connection with recent FERC orders;

•

Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;

•

Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion;

•

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

•

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

•

Adverse outcomes in litigation matters or regulatory proceedings.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011.

Dominion’s and Virginia Power’s forward-looking statements are based on beliefs and assumptions using information available at the time the statements are made. The Companies caution the reader not to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. Dominion and Virginia Power 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, 2012, there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011. The policies disclosed included the accounting for regulated operations, AROs, income taxes, derivative contracts and other instruments at fair value, goodwill and long-lived asset impairment testing, employee benefit plans and unbilled revenue.

Use of Estimates in Long-Lived Asset Impairment Testing

See Note 15 to the Consolidated Financial Statements in this report for a discussion of potential impairments related to Brayton Point, Kincaid, and Dominion’s interest in Elwood.

Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about operating the long-lived assets and the selection of an appropriate discount rate. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed, and expected proceeds from dispositions.

Dominion

Results of Operations

Presented below is a summary of Dominion’s consolidated results:


	2012		2011		$ Change
(millions, except EPS)
Third Quarter
Net income attributable to Dominion	$	209	$	392	$	(183	)
Diluted EPS		0.36		0.69		(0.33	)
Year-To-Date
Net income attributable to Dominion	$	961	$	1,207	$	(246	)
Diluted EPS		1.68		2.10		(0.42	)

Overview

Third Quarter 2012 vs. 2011

Net income attributable to Dominion decreased by 47%. Unfavorable drivers include impairment and other charges related to management’s decision to cease operations and begin decommissioning Kewaunee in 2013 and the impact of less favorable weather on Dominion’s electric utility operations. Favorable drivers include the absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene and the absence of a charge recorded in 2011 related to the impairment of SO ₂ emissions allowances not expected to be consumed due to CSAPR.

Year-To-Date 2012 vs. 2011

Net income attributable to Dominion decreased by 20%. Unfavorable drivers include impairment and other charges related to management’s decision to cease operations and begin decommissioning Kewaunee in 2013, lower margins from merchant generation operations, and the impact of less favorable weather on Dominion’s electric utility operations. Favorable drivers include the absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene and the absence of a charge recorded in 2011 related to the impairment of SO ₂ emissions allowances not expected to be consumed due to CSAPR.

PAGE 55

Analysis of Consolidated Operations

Presented below are selected amounts related to Dominion’s results of operations:


	Third Quarter								Year-To-Date
	2012			2011		$ Change			2012			2011			$ Change
(millions)
Operating revenue	$	3,411		$	3,745	$	(334	)	$	9,926		$	11,016		$	(1,090	)
Electric fuel and other energy-related purchases		1,052			1,217		(165	)		2,893			3,195			(302	)
Purchased electric capacity		86			109		(23	)		297			344			(47	)
Purchased gas		191			335		(144	)		818			1,342			(524	)

Net revenue		2,082			2,084		(2	)		5,918			6,135			(217	)

Other O&M		1,134			859		275			2,549			2,387			162
Depreciation, depletion and amortization		306			268		38			882			783			99
Other taxes		124			129		(5	)		439			411			28
Other income		56			16		40			174			112			62
Interest and related charges		215			249		(34	)		667			691			(24	)
Income tax expense		139			203		(64	)		552			730			(178	)
Income (loss) from discontinued operations		(5	)		4		(9	)		(22	)		(26	)		4

An analysis of Dominion’s results of operations follows:

Third Quarter 2012 vs. 2011

Net revenue decreased $2 million, primarily reflecting:

•

A $49 million decrease from merchant generation operations primarily due to a decrease in realized prices; and

•

A $7 million decrease in retail energy marketing activities primarily due to price risk management activities.

These decreases were partially offset by:

•

A $43 million increase from electric utility operations primarily reflecting:

•

An increase in rate adjustment clause revenue ($54 million); and

•

A $7 million increase related to PJM ancillary revenues reflecting the absence of an accrual for anticipated billing adjustments from PJM for certain ancillary revenues recognized in 2011 and 2010 ($35 million), partially offset by other ancillary revenue decreases ($28 million); partially offset by

•

The impact ($22 million) of a decrease in sales to retail customers primarily due to a decrease in cooling degree days ($65 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($43 million); and

•

A $13 million increase in producer services primarily related to favorable price changes on economic hedging positions partially offset by lower physical margins, all associated with natural gas aggregation, marketing and trading activities.

Other O&M increased 32%, primarily reflecting:

•

A $434 million increase due to impairment and other charges related to management’s decision to cease operations and begin decommissioning Kewaunee in 2013.

This increase was partially offset by:

•

A $121 million decrease due to the absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene; and

•

A $57 million decrease due to the absence of impairment charges recorded in 2011 related to excess SO ₂ emission allowances resulting from CSAPR.

PAGE 56

Depreciation, depletion and amortization increased 14%, primarily due to property additions.

Other income increased $40 million, primarily due to higher realized gains (including investment income) on nuclear decommissioning trust funds.

Interest and related charges decreased 14%, primarily due to favorable changes on interest rate derivatives ($13 million), the absence of interest accrued in 2011 relating to resolutions with taxing authorities ($11 million), a decrease in interest expense associated with the September 2006 hybrids due to a lower interest rate and the tender offer in early 2012 ($5 million), and higher capitalized interest related to AFUDC as a result of construction and expansion projects ($4 million).

Income tax expense decreased 32%, primarily reflecting lower pre-tax income in 2012, partially offset by a higher effective income tax rate.

Year-To-Date 2012 vs. 2011

Net revenue decreased 4%, primarily reflecting:

•

A $132 million decrease from regulated natural gas distribution operations primarily reflecting decreased rider revenue ($110 million) related to low income assistance programs;

•

A $140 million decrease from merchant generation operations primarily reflecting a decrease in realized prices; and

•

A $10 million decrease in producer services primarily related to lower physical margins partially offset by favorable price changes on economic hedging positions, all associated with natural gas aggregation, marketing and trading activities.

These decreases were partially offset by:

•

A $72 million increase in retail energy marketing activities primarily due to price risk management activities ($45 million) and the impact of higher margins on electric sales ($35 million) due to lower purchased power costs partially offset by lower power sales prices; and

•

A $23 million increase from electric utility operations primarily reflecting:

•

An increase in rate adjustment clause revenue ($113 million);

•

A decrease in net capacity expenses ($28 million); and

•

The absence of a 2011 deferred fuel adjustment ($9 million); partially offset by

•

The impact ($110 million) of a decrease in sales to retail customers primarily due to a decrease in cooling and heating degree days ($209 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($99 million); and

•

A $15 million decrease related to PJM ancillary revenues reflecting ancillary revenue decreases ($50 million), partially offset by the absence of an accrual for anticipated billing adjustments from PJM for certain ancillary revenues recognized in 2011 and 2010 ($35 million).

Other O&M increased 7%, primarily reflecting:

•

A $434 million increase due to impairment and other charges related to management’s decision to cease operations and begin decommissioning Kewaunee in 2013;

•

A $61 million increase in certain electric transmission-related expenditures. These expenses are recovered through FERC rates; and

•

A $48 million increase in storm damage and service restoration costs primarily due to the damage caused by late June summer storms in 2012.

These increases were partially offset by:

•

A $121 million decrease due to the absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene;

•

A $110 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These expenses are recovered through rates and do not impact net income;

•

A $57 million decrease due to the absence of impairment charges recorded in 2011 related to excess SO ₂ emission allowances resulting from CSAPR;

•

A $56 million decrease attributable to increased deferrals for construction activities related to regulated operations; and

•

A $52 million decrease in rent expense due to the consolidation of Fairless in October 2011.

Depreciation, depletion and amortization increased 13%, primarily due to property additions.

Other taxes increased 7%, primarily reflecting the Connecticut electric generation tax enacted in the second half of 2011.

PAGE 57

Other income increased 55%, primarily due to higher realized gains (including investment income) on nuclear decommissioning trust funds ($44 million) and an increase in the equity component of AFUDC ($13 million).

Interest and related charges decreased 3%, primarily due to favorable changes on interest rate derivatives ($17 million) and a decrease in interest expense associated with the September 2006 hybrids due to a lower interest rate and the tender offer in early 2012 ($14 million), partially offset by a net increase due to the consolidation of Juniper debt in October 2011 ($10 million).

Income tax expense decreased 24%, primarily reflecting lower pre-tax income in 2012.

PAGE 58

Segment Results of Operations

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. Presented below is a summary of contributions by Dominion’s operating segments to net income attributable to Dominion:


	Net Income attributable to Dominion									Diluted EPS
Third Quarter	2012			2011			$ Change			2012			2011			$ Change
(millions, except EPS)
DVP	$	119		$	125		$	(6	)	$	0.21		$	0.22		$	(0.01	)
Dominion Generation		363			380			(17	)		0.63			0.66			(0.03	)
Dominion Energy		104			95			9			0.18			0.17			0.01

Primary operating segments		586			600			(14	)		1.02			1.05			(0.03	)
Corporate and Other		(377	)		(208	)		(169	)		(0.66	)		(0.36	)		(0.30	)

Consolidated	$	209		$	392		$	(183	)	$	0.36		$	0.69		$	(0.33	)


Year-To-Date
DVP	$	428		$	389		$	39		$	0.75		$	0.68		$	0.07
Dominion Generation		737			852			(115	)		1.29			1.48			(0.19	)
Dominion Energy		362			368			(6	)		0.63			0.64			(0.01	)

Primary operating segments		1,527			1,609			(82	)		2.67			2.80			(0.13	)
Corporate and Other		(566	)		(402	)		(164	)		(0.99	)		(0.70	)		(0.29	)

Consolidated	$	961		$	1,207		$	(246	)	$	1.68		$	2.10		$	(0.42	)

DVP

Presented below are selected operating statistics related to DVP’s operations:


	Third Quarter							Year-To-Date
	2012		2011		% Change			2012		2011		% Change
Electricity delivered (million MWh)		23.0		23.1		—	%		61.7		63.9		(3	)%
Degree days (electric distribution service area):

Cooling		1,198		1,238		(3	)		1,734		1,869		(7	)
Heating		5		12		(58	)		1,707		2,302		(26	)
Average electric distribution customer accounts (thousands) ⁽¹⁾		2,457		2,438		1			2,452		2,436		1
Average retail energy marketing customer accounts (thousands) ⁽¹⁾		2,132		2,181		(2	)		2,127		2,154		(1	)

(1)	Period average.

PAGE 59

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


	Third Quarter 2012 vs. 2011 Increase (Decrease)						Year-To-Date 2012 vs. 2011 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(11	)	$	(0.02	)	$	(39	)	$	(0.07	)
Other		7			0.01			19			0.03
FERC transmission equity return		3			0.01			15			0.02
Retail energy marketing operations		(6	)		(0.01	)		45			0.08
Storm damage and service restoration ⁽¹⁾		2			—			13			0.02
Other		(1	)		—			(14	)		(0.02	)
Share accretion		—			—			—			0.01

Change in net income contribution	$	(6	)	$	(0.01	)	$	39		$	0.07

(1)	Excludes restoration costs associated with damage caused by late June 2012 summer storms and Hurricane Irene reflected in the Corporate and Other segment.

Dominion Generation

Presented below are selected operating statistics related to Dominion Generation’s operations:


	Third Quarter							Year-To-Date
	2012		2011		% Change			2012		2011		% Change
Electricity supplied (million MWh):
Utility		23.1		23.1		—	%		61.8		63.9		(3	)%
Merchant ⁽¹⁾		11.2		11.7		(3	)		31.7		33.6		(5	)
Degree days (electric utility service area):
Cooling		1,198		1,238		(3	)		1,734		1,869		(7	)
Heating		5		12		(58	)		1,707		2,302		(26	)

(1)	Includes 4.0 and 4.7 million MWh for the three months ended September 30, 2012 and 2011, respectively, and 10.0 and 14.0 million MWh for the nine months ended September 30, 2012 and 2011, respectively, related to Kewaunee, State Line, Salem Harbor, Brayton Point, Kincaid, and Elwood.

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


	Third Quarter 2012 vs. 2011 Increase (Decrease)						Year-To-Date 2012 vs. 2011 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)

Merchant generation margin	$	(20	)	$	(0.04	)	$	(96	)	$	(0.17	)
Regulated electric sales:
Weather		(29	)		(0.05	)		(88	)		(0.16	)
Other		19			0.03			34			0.06
Brayton Point, Kincaid and Elwood third quarter 2011 earnings ⁽¹⁾		(9	)		(0.02	)		(9	)		(0.02	)
Rate adjustment clause equity return		6			0.01			7			0.01
PJM ancillary services		(3	)		(0.01	)		(28	)		(0.05	)
Net capacity expenses		3			0.01			18			0.04
Outage costs		5			0.01			21			0.04
Other		11			0.02			26			0.05
Share accretion		—			0.01			—			0.01

Change in net income contribution	$	(17	)	$	(0.03	)	$	(115	)	$	(0.19	)

(1)	Brayton Point’s, Kincaid’s and Elwood’s third quarter 2012 results of operations have been reflected in the Corporate and Other segment due to Dominion’s decision, in the third quarter of 2012, to pursue the sale of these three power stations.

PAGE 60

Dominion Energy

Presented below are selected operating statistics related to Dominion Energy’s operations:


	Third Quarter							Year-To-Date
	2012		2011		% Change			2012		2011		% Change
Gas distribution throughput (bcf):
Sales		2		2		—	%		17		22		(23	)%
Transportation		40		33		21			185		188		(2	)
Heating degree days (gas distribution service area)		142		88		61			3,030		3,844		(21	)
Average gas distribution customer accounts (thousands) ⁽¹⁾ :
Sales		245		251		(2	)		249		253		(2	)
Transportation		1,037		1,029		1			1,046		1,044		—

(1)	Period average.

PAGE 61

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


	Third Quarter 2012 vs. 2011 Increase (Decrease)				Year-To-Date 2012 vs. 2011 Increase (Decrease)
	Amount		EPS		Amount			EPS
(millions, except EPS)
Weather	$	1	$	—	$	(6	)	$	(0.01	)
Producer services margin		7		0.01		(8	)		(0.01	)
Gas transmission margin		—		—		(6	)		(0.01	)
Other		1		—		14			0.02

Change in net income contribution	$	9	$	0.01	$	(6	)	$	(0.01	)

Corporate and Other

Presented below are the Corporate and Other segment’s after-tax results:


	Third Quarter									Year-To-Date
	2012			2011			$ Change			2012			2011			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	(326	)	$	(147	)	$	(179	)	$	(397	)	$	(183	)	$	(214	)
Specific items attributable to corporate operations		9			12			(3	)		9			4			5

Total specific items		(317	)		(135	)		(182	)		(388	)		(179	)		(209	)
Other corporate operations		(60	)		(73	)		13			(178	)		(223	)		45

Total net benefit (expense)	$	(377	)	$	(208	)	$	(169	)	$	(566	)	$	(402	)	$	(164	)
EPS impact	$	(0.66	)	$	(0.36	)	$	(0.30	)	$	(0.99	)	$	(0.70	)	$	(0.29	)

Total Specific Items

Corporate and Other includes specific items that are not included in profit measures evaluated by management in assessing segment performance or in allocating resources among the segments. See Note 19 to the Consolidated Financial Statements in this report for discussion of these items.

Other Corporate Operations

Year-To-Date 2012 vs. 2011

Net expenses decreased primarily due to lower state income tax expense and lower net interest expense.

PAGE 62

Virginia Power

Results of Operations

Presented below is a summary of Virginia Power’s consolidated results:


	Third Quarter						Year-To-Date
	2012		2011		$ Change		2012		2011		$ Change
(millions)
Net income	$	415	$	297	$	118	$	830	$	816	$	14

Overview

Third Quarter 2012 vs. 2011

Net income increased by 40% primarily due to the absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene, the absence of a charge recorded in 2011 related to the impairment of SO ₂ emissions allowances not expected to be consumed due to CSAPR, partially offset by the impact of less favorable weather.

Year-To-Date 2012 vs. 2011

Net income increased by 2%. Favorable drivers include the absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene, the absence of a charge recorded in 2011 related to the impairment of SO ₂ emissions allowances not expected to be consumed due to CSAPR, and the impact of favorable economic conditions on customer usage and other factors. Unfavorable drivers include the restoration costs associated with damage caused by late June 2012 summer storms and the impact of less favorable weather.

Analysis of Consolidated Operations

Presented below are selected amounts related to Virginia Power’s results of operations:


	Third Quarter							Year-To-Date
	2012		2011		$ Change			2012		2011		$ Change
(millions)
Operating revenue	$	2,086	$	2,177	$	(91	)	$	5,596	$	5,691	$	(95	)
Electric fuel and other energy-related purchases		634		746		(112	)		1,850		1,922		(72	)
Purchased electric capacity		86		108		(22	)		296		342		(46	)

Net revenue		1,366		1,323		43			3,450		3,427		23

Other O&M		369		514		(145	)		1,117		1,172		(55	)
Depreciation and amortization		203		184		19			579		533		46
Other taxes		48		57		(9	)		179		172		7
Other income		25		25		—			65		64		1
Interest and related charges		97		114		(17	)		297		290		7
Income tax expense		259		182		77			513		508		5

An analysis of Virginia Power’s results of operations follows:

Third Quarter 2012 vs. 2011

Net revenue increased 3%, primarily reflecting:

•

An increase in rate adjustment clause revenue ($54 million); and

•

Other O&M decreased 28%, primarily reflecting:

•

A $121 million decrease due to the absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene; and

•

A $43 million decrease due to the absence of impairment charges recorded in 2011 related to excess SO ₂ emission allowances resulting from CSAPR; partially offset by

PAGE 63

•

A $26 million increase in certain electric transmission-related expenditures. These expenses are recovered through FERC rates.

Depreciation and amortization increased 10%, primarily due to property additions.

Interest and related charges decreased 15%, primarily due to the absence of interest accrued in 2011 relating to resolutions with taxing authorities ($11 million) and higher capitalized interest related to AFUDC as a result of construction and expansion projects ($3 million).

Income tax expense increased 42%, primarily reflecting higher pre-tax income in 2012.

Year-To-Date 2012 vs. 2011

Net revenue increased 1%, primarily reflecting:

•

An increase in rate adjustment clause revenue ($113 million);

•

A decrease in net capacity expenses ($28 million); and

•

The absence of a 2011 deferred fuel adjustment ($9 million); partially offset by

•

Other O&M decreased 5%, primarily reflecting:

•

A $121 million decrease due to the absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene;

•

A $43 million decrease due to the absence of impairment charges recorded in 2011 related to excess SO ₂ emission allowances resulting from CSAPR; and

•

A $27 million decrease attributable to increased deferrals for construction activities related to regulated operations.

These decreases were partially offset by:

•

A $61 million increase in certain electric transmission-related expenditures. These expenses are recovered through FERC rates;

•

A $47 million increase in storm damage and service restoration costs primarily due to the damage caused by late June 2012 summer storms; and

•

A $29 million increase in planned outage costs due to an increase in scheduled outage days at certain nuclear generation facilities.

Depreciation and amortization increased 9%, primarily due to property additions.

Segment Results of Operations

Presented below is a summary of contributions by Virginia Power’s operating segments to net income:


	Third Quarter								Year-To-Date
	2012		2011			$ Change			2012			2011			$ Change
(millions)
DVP	$	128	$	127		$	1		$	335		$	342		$	(7	)
Dominion Generation		283		289			(6	)		534			598			(64	)

Primary operating segments		411		416			(5	)		869			940			(71	)
Corporate and Other		4		(119	)		123			(39	)		(124	)		85

Consolidated	$	415	$	297		$	118		$	830		$	816		$	14

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DVP

Presented below are operating statistics related to Virginia Power’s DVP segment:


	Third Quarter							Year-To-Date
	2012		2011		% Change			2012		2011		% Change
Electricity delivered (million MWh)		23.0		23.1		—	%		61.7		63.9		(3	)%
Degree days (electric distribution service area):
Cooling		1,198		1,238		(3	)		1,734		1,869		(7	)
Heating		5		12		(58	)		1,707		2,302		(26	)
Average electric distribution customer accounts (thousands) ⁽¹⁾		2,457		2,438		1			2,452		2,436		1

(1)	Period average.

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


	Third Quarter 2012 vs. 2011 Increase (Decrease)			Year-To-Date 2012 vs. 2011 Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	(11	)	$	(39	)
Other		7			19
FERC transmission equity return		3			15
Storm damage and service restoration ⁽¹⁾		2			13
Other		—			(15	)

Change in net income contribution	$	1		$	(7	)

(1)	Excludes restoration costs associated with damage caused by late June 2012 summer storms and Hurricane Irene reflected in the Corporate and Other segment.

Dominion Generation

Presented below are operating statistics related to Virginia Power’s Dominion Generation segment:


	Third Quarter							Year-To-Date
	2012		2011		% Change			2012		2011		% Change
Electricity supplied (million MWh):		23.1		23.1		—	%		61.8		63.9		(3	)%
Degree days (electric utility service area):
Cooling		1,198		1,238		(3	)		1,734		1,869		(7	)
Heating		5		12		(58	)		1,707		2,302		(26	)

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


	Third Quarter 2012 vs. 2011 Increase (Decrease)			Year-To-Date 2012 vs. 2011 Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	(29	)	$	(88	)
Other		19			34
Rate adjustment clause equity return		6			7
PJM ancillary services		(3	)		(28	)
Net capacity expenses		3			18
Outage costs		4			(14	)
Other		(6	)		7

Change in net income contribution	$	(6	)	$	(64	)

Corporate and Other

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Selected Information - Energy Trading Activities

Dominion engages in energy trading, marketing and hedging activities to complement its businesses and facilitate its price risk management activities. As part of these operations, Dominion enters into contracts for purchases and sales of energy-related commodities, including electricity, natural gas and other energy-related products. Settlements of contracts may require physical delivery of the underlying commodity or cash settlement. Dominion also enters into contracts with the objective of benefiting from changes in prices. For example, after entering into a contract to purchase a commodity, Dominion typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, Dominion may receive a net cash margin (a realized gain), or may pay a net cash margin (a realized loss). Dominion continually monitors its contract positions, considering location and timing of delivery or settlement for each energy commodity in relation to market price activity.

A summary of the changes in the unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes follows:


	Amount
(millions)
Net unrealized gain at December 31, 2011	$	20
Contracts realized or otherwise settled during the period		4
Change in unrealized gains and losses		50

Net unrealized gains at September 30, 2012	$	74

The balance of net unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes at September 30, 2012, is summarized in the following table based on the approach used to determine fair value:


Maturity Based on Contract Settlement or Delivery Date(s)
Sources of Fair Value	2012		2013 - 2014		2015 - 2016		2017 and thereafter			Total
Prices actively quoted - Level 1 ⁽¹⁾	$	—	$	—	$	—	$	—		$	—
Prices provided by other external sources - Level 2 ⁽²⁾		16		52		5		—			73
Prices based on models and other valuation methods - Level 3 ⁽³⁾		—		3		—		(2	)		1

Total	$	16	$	55	$	5	$	(2	)	$	74

(1)	Values represent observable unadjusted quoted prices for traded instruments in active markets.

(2)	Values with inputs that are observable directly or indirectly for the instrument, but do not qualify for Level 1.

(3)	Values with a significant amount of inputs that are not observable for the instrument.

Liquidity and Capital Resources

Dominion and Virginia Power 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, 2012, Dominion had $2.1 billion of unused capacity under its credit facilities, including $1.1 billion of unused capacity under joint credit facilities available to Virginia Power.

The sales of Salem Harbor and State Line, which were classified as discontinued operations in the second quarter of 2012, are not expected to negatively impact Dominion’s liquidity.

The decision to cease generation operations at Kewaunee in 2013 and commence decommissioning of the facility is not expected to negatively impact Dominion’s liquidity. Dominion believes that the amounts currently available in Kewaunee’s decommissioning trust and their expected earnings will be sufficient to cover expected decommissioning costs.

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A summary of Dominion’s cash flows is presented below:


	2012			2011
(millions)
Cash and cash equivalents at January 1	$	102		$	62
Cash flows provided by (used in):
Operating activities		3,462			2,398
Investing activities		(2,784	)		(2,364	)
Financing activities		(699	)		116

Net increase (decrease) in cash and cash equivalents		(21	)		150

Cash and cash equivalents at September 30	$	81		$	212

A summary of Virginia Power’s cash flows is presented below:


	2012			2011
(millions)
Cash and cash equivalents at January 1	$	29		$	5
Cash flows provided by (used in):
Operating activities		2,287			1,697
Investing activities		(1,551	)		(1,431	)
Financing activities		(744	)		(247	)

Net increase (decrease) in cash and cash equivalents		(8	)		19

Cash and cash equivalents at September 30	$	21		$	24

Operating Cash Flows

Net cash provided by Dominion’s operating activities increased by approximately $1.1 billion, primarily due to higher deferred fuel cost recoveries in its Virginia jurisdiction, lower margin collateral requirements, changes in other working capital items and income tax refunds in 2012 as compared to income tax payments in 2011. The increase was partially offset by lower merchant generation margins and the impact of less favorable weather.

Net cash provided by Virginia Power’s operating activities increased by $590 million, primarily due to higher deferred fuel cost recoveries in its Virginia jurisdiction and net changes in other working capital items. The increase was partially offset by higher income tax payments and the impact of less favorable weather.

Dominion believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. Virginia Power believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and provide dividends to Dominion.

The Companies’ 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 Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011.

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Credit Risk

Dominion’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion’s credit exposure as of September 30, 2012 for these activities. Gross credit exposure for each counterparty is calculated prior to the application of collateral and represents 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⁾	$	349	$	5	$	344
Non-investment grade ⁽²⁾		5		—		5
No external ratings:
Internally rated – investment grade ⁽³⁾		82		—		82
Internally rated – non-investment grade ⁽⁴⁾		93		—		93

Total	$	529	$	5	$	524

(1)	Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 36% of the total net credit exposure.

(2)	The five largest counterparty exposures, combined, for this category represented approximately 1% of the total net credit exposure.

(3)	The five largest counterparty exposures, combined, for this category represented approximately 8% of the total net credit exposure.

(4)	The five largest counterparty exposures, combined, for this category represented approximately 11% of the total net credit exposure.

Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. At September 30, 2012, Virginia Power’s exposure to potential concentrations of credit risk was not considered material.

Investing Cash Flows

Net cash used in Dominion’s investing activities increased by $420 million primarily due to higher capital expenditures, mainly related to investments in growth projects, and lower restricted cash reimbursements for the purpose of funding certain qualifying construction projects.

Net cash used in Virginia Power’s investing activities increased by $120 million, primarily due to lower restricted cash reimbursements for the purpose of funding certain qualifying construction projects.

Financing Cash Flows and Liquidity

Dominion and Virginia Power rely on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by their operations. As discussed further in Credit Ratings and Debt Covenants in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011, the Companies’ ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC and, in the case of Virginia Power, approval by the Virginia Commission.

Each of the Companies meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933, as amended. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows the Companies to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.

For the nine months ended September 30, 2012, net cash used in Dominion’s financing activities was $699 million as compared to net cash provided by financing activities of $116 million in 2011, primarily due to lower net debt issuances in 2012 as a result of higher cash inflow from operations, partially offset by higher issuances of common stock in 2012 and the absence of the repurchase of common stock recorded in 2011.

Net cash used in Virginia Power’s financing activities increased $497 million, primarily due to net debt repayments in 2012 as compared to net debt issuances in 2011 as a result of higher cash inflow from operations.

See Note 14 to the Consolidated Financial Statements in this report for further information regarding Dominion’s and Virginia Power’s credit facilities, liquidity and significant financing transactions.

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Credit Ratings

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 section of MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011, there is a discussion on the use of capital markets by the Companies, as well as the impact of credit ratings on the accessibility and costs of using these markets. As of September 30, 2012, there have been no changes in the Companies’ credit ratings.

Debt Covenants

In the Debt Covenants section of MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011, there is a discussion on the various covenants present in the enabling agreements underlying the Companies’ debt. Also, as disclosed in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, modifications were made to certain debt covenants in Virginia Power’s Indenture of Mortgage, primarily for ease of administration. No mortgage bonds are outstanding. As of September 30, 2012, there have been no material changes to debt covenants, nor any events of default under the Companies’ debt covenants.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of September 30, 2012, there have been no material changes outside the ordinary course of business to Dominion’s or Virginia Power’s contractual obligations nor any material changes to planned capital expenditures as disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2011.

Use of Off-Balance Sheet Arrangements

As of September 30, 2012, there have been no material changes in the off-balance sheet arrangements disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2011.

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, the dates of Dominion’s and Virginia Power’s Consolidated Financial Statements that may impact the Companies’ future results of operations, financial condition and/or cash flows. This section should be read in conjunction with Item 1. Business and Future Issues and Other Matters in Item 7. MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011 and Future Issues and Other Matters in Dominion’s and Virginia Power’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012.

Environmental Matters

Dominion and Virginia Power 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. See Note 23 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011, Note 12 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, Note 14 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 and Note 15 in this report for additional information on various environmental matters.

Regulatory Matters

See Note 14 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011, Note 9 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 and Note 11 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 and in this report for additional information on various regulatory matters.

Dominion NGL Pipelines

In May 2012, Dominion began construction of a $125 million pipeline project designed to transport approximately 27,000 barrels per day of ethane from its processing and fractionation facility being built near Natrium, West Virginia to an interconnect with the ATEX line of Enterprise near Follansbee, West Virginia. Dominion NGL Pipelines, LLC, a subsidiary of Dominion, will own the 58-mile pipeline and associated equipment. The facilities are anticipated to be available the later of January 1, 2014 or the date Enterprise commences operation of the ATEX line. Transportation services on the pipeline will be subject to FERC regulation under the Interstate Commerce Act.

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Electric Transmission Projects

In August 2012, Virginia Power requested Virginia Commission approval of the Harrisonburg-to-Endless Caverns line. The proposed project is estimated to cost approximately $66 million. Subject to the receipt of applicable state and federal regulatory approvals, the Harrisonburg-to-Endless Caverns line is expected to be completed by May 2015.

Legal Matters

See Item 3. Legal Proceedings in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011, Notes 9 and 12 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, Notes 11 and 14 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 and Notes 11 and 15 in this report for additional information on various legal matters.

Cove Point Export Project

Dominion is pursuing a liquefaction project at Cove Point, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. The project, which is expected to cost between approximately $2.5 and $3.5 billion, exclusive of financing costs, has a planned capacity of approximately 750 million cubic feet per day on the inlet and approximately 4.5 to 5 million metric tons per annum on the outlet. In March 2012, Cove Point entered into precedent agreements with two major companies, one of which is Sumitomo Corporation, pursuant to which Cove Point would provide liquefaction, storage and loading services but would not own or directly export the LNG. In October 2012, Dominion and the unnamed company terminated their precedent agreement by mutual consent. Dominion is in active negotiations with Sumitomo and multiple other potential customers for definitive terminal service agreements for the planned project capacity. Dominion expects to finalize the terminal service agreements by the end of this year.

Subject to a final decision on pursuing the project, execution of binding terminal service agreements, receipt of regulatory and other approvals, and successful completion of engineering studies, construction of liquefaction facilities could begin in 2014 with an in-service date in 2017.

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ITEM 3.

QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part I, Item 2. MD&A of this Form 10-Q. The reader’s attention is directed to those paragraphs for discussion of various risks and uncertainties that may impact Dominion and Virginia Power.

Market Risk Sensitive Instruments and Risk Management

Dominion’s and Virginia Power’s 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 present in Dominion’s and Virginia Power’s electric operations, Dominion’s gas procurement operations, and Dominion’s energy marketing and trading operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt. In addition, they are exposed to investment price risk through various portfolios of equity and debt 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 or interest rates.

Commodity Price Risk

To manage price risk, Dominion and Virginia Power primarily hold commodity-based financial derivative instruments for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products. As part of its strategy to market energy and to manage related risks, Dominion also holds commodity-based financial derivative instruments for trading purposes.

The derivatives used to manage 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 of Dominion’s non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $175 million and $179 million as of September 30, 2012 and December 31, 2011, respectively. A hypothetical 10% unfavorable change in commodity prices of Dominion’s commodity-based financial derivative instruments held for trading purposes would have resulted in a decrease in fair value of approximately $15 million and $8 million as of September 30, 2012 and December 31, 2011, respectively.

A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of Virginia Power’s non-trading commodity-based financial derivatives as of September 30, 2012 or December 31, 2011.

The impact of a change in energy commodity prices on Dominion’s and Virginia Power’s non-trading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.

Interest Rate Risk

Dominion and Virginia Power manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt and interest rate swaps designated under fair value hedging and outstanding for Dominion and Virginia Power, a hypothetical 10% increase in market interest rates would not have resulted in a material change in annual earnings at September 30, 2012 or December 31, 2011.

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Additionally, Dominion and Virginia Power may use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. As of September 30, 2012, Dominion and Virginia Power had $2.2 billion and $1.2 billion, respectively, 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 $31 million and $20 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at September 30, 2012.

The impact of a change in interest rates on Dominion’s and Virginia Power’s interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.

Investment Price Risk

Dominion and Virginia Power are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value.

Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $87 million, $22 million and $54 million for the nine months ended September 30, 2012 and 2011 and for the year ended December 31, 2011, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $239 million and $52 million for the nine months ended September 30, 2012 and for the year ended December 31, 2011, respectively, and a net decrease in unrealized gains on these investments of $118 million for the nine months ended September 30, 2011.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $32 million, $8 million and $24 million for the nine months ended September 30, 2012 and 2011 and for the year ended December 31, 2011, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $101 million and $25 million for the nine months ended September 30, 2012 and for the year ended December 31, 2011, respectively, and a net decrease in unrealized gains on these investments of $43 million for the nine months ended September 30, 2011.

Dominion sponsors employee pension and OPEB plans, in which Dominion’s and Virginia Power’s employees participate, that hold investments in trusts to fund benefit payments. If the values of investments held in these trusts decline, it 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 contributions to be made to the employee benefit plans.

ITEM 4. CONTROLS AND PROCEDURES

Senior management of each of Dominion and Virginia Power, including Dominion’s and Virginia Power’s CEO and CFO, evaluated the effectiveness of each of their respective Companies’ disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, each of Dominion’s and Virginia Power’s CEO and CFO have concluded that each of their respective Companies’ disclosure controls and procedures are effective.

There were no changes in either Dominion’s or Virginia Power’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, either of the Companies’ internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, Dominion and Virginia Power are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Companies, or permits issued by various local, state and/or 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, the Companies and their subsidiaries are involved in various legal proceedings. Other than the matter discussed below, there have been no material changes to the legal proceedings reported in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011.

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See the following for discussions on various environmental and other regulatory proceedings to which the Companies are a party:

•

Notes 14 and 23 to the Consolidated Financial Statements and Future Issues and Other Matters in MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011.

•

Notes 9 and 12 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

•

Notes 11 and 14 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012.

•

Notes 11 and 15 in this report.

ITEM 1A. RISK FACTORS

Dominion’s and Virginia Power’s businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond the Companies’ control. A number of these risk factors have been identified in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011, 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 Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2011. 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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Dominion

ISSUER PURCHASES OF EQUITY SECURITIES


Period	Total Number of Shares (or Units) Purchased ⁽¹⁾		Average Price Paid per Share (or Unit) ⁽²⁾		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs ⁽³⁾
7/1/12-7/31/12		329	$	54.00		—	19,629,059 shares/ $1.18 billion
8/1/12-8/31/12		—		—		—	19,629,059 shares/ $1.18 billion
9/1/12-9/30/12		2,107		52.48		—	19,629,059 shares/ $1.18 billion

Total		2,436	$	52.69		—	19,629,059 shares/ $1.18 billion

(1)	In July and September 2012, 329 shares and 2,107 shares, respectively, were tendered by employees to satisfy tax withholding obligations on vested restricted stock.

(2)	Represents the weighted-average price paid per share.

(3)

The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion BOD in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion BOD was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion.

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ITEM 6. EXHIBITS


Exhibit Number	Description	Dominion	Virginia Power

3.1.a	Dominion Resources, Inc. Articles of Incorporation as amended and restated effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).	X

3.1.b	Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on March 3, 2011 (Exhibit 3.1b, Form 10-Q for the quarter ended March 30, 2011 filed April 29, 2011, File No. 1-2255).		X

3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective December 13, 2011 (Exhibit 3.1, Form 8-K filed December 14, 2011, File No. 1-8489).	X

3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).		X

4	Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.	X	X

PAGE 76



4.1	Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K filed June 22, 2000, File No. 1-8489); Forms of Second and Third Supplemental Indentures, dated July 1, 2000 (Exhibits 4.2 and 4.3, Form 8-K filed July 11, 2000, File No. 1-8489); Fourth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.2, Form 8-K filed September 8, 2000, File No. 1-8489); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K filed September 11, 2000, File No. 1-8489); Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Forms of Seventeenth and Eighteenth Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489); Forms of Twentieth and Twenty-First Supplemental Indentures, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Third Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011 (Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K filed March 7, 2011, File No. 1-8489); Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K filed August 15, 2011, File No. 1-8489); Forty-Fifth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K filed September 13, 2012, File No. 1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K filed September 13, 2012, File No. 1-8489).	X

12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X

12.2.a	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).		X

PAGE 77



12.2.b	Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).		X

31.a	Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X

31.b	Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X

31.c	Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X

31.d	Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X

32.a	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).	X

32.b	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X

99	Condensed consolidated earnings statements (filed herewith).	X	X

101^	The following financial statements from Dominion Resources, Inc.’s and Virginia Electric and Power Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed on October 25, 2012, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.	X	X

This exhibit will not be deemed “filed” by Virginia Electric and Power Company for purposes of Section 18 of the Securities Exchange Act of 1934 (15 U.S.C. 78r), or otherwise subject to the liability of that section. Such exhibit will not be deemed to be incorporated by reference into any filing under the Securities Act or Securities Exchange Act, except to the extent that Virginia Electric and Power Company specifically incorporates it by reference.

PAGE 78

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.


				DOMINION RESOURCES, INC. Registrant

October 25, 2012				/s/ Ashwini Sawhney
				Ashwini Sawhney Vice President – Accounting and Controller (Chief Accounting Officer)

				VIRGINIA ELECTRIC AND POWER COMPANY Registrant

October 25, 2012				/s/ Ashwini Sawhney
				Ashwini Sawhney Vice President – Accounting (Chief Accounting Officer)

PAGE 79

EXHIBIT INDEX


Exhibit Number	Description	Dominion	Virginia Power

3.1.a	Dominion Resources, Inc. Articles of Incorporation as amended and restated effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).	X

3.1.b	Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on March 3, 2011 (Exhibit 3.1b, Form 10-Q for the quarter ended March 30, 2011 filed April 29, 2011, File No. 1-2255).		X

3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective December 13, 2011 (Exhibit 3.1, Form 8-K filed December 14, 2011, File No. 1-8489).	X

3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).		X

4	Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.	X	X

PAGE 80



4.1	Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K filed June 22, 2000, File No. 1-8489); Forms of Second and Third Supplemental Indentures, dated July 1, 2000 (Exhibits 4.2 and 4.3, Form 8-K filed July 11, 2000, File No. 1-8489); Fourth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.2, Form 8-K filed September 8, 2000, File No. 1-8489); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K filed September 11, 2000, File No. 1-8489); Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Forms of Seventeenth and Eighteenth Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489); Forms of Twentieth and Twenty-First Supplemental Indentures, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Third Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011 (Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K filed March 7, 2011, File No. 1-8489); Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K filed August 15, 2011, File No. 1-8489); Forty-Fifth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K filed September 13, 2012, File No. 1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K filed September 13, 2012, File No. 1-8489).	X

12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X

12.2.a	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).		X

PAGE 81



12.2.b	Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).		X

31.a	Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X

31.b	Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X

31.c	Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X

31.d	Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X

32.a	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).	X

32.b	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X

99	Condensed consolidated earnings statements (filed herewith).	X	X

101^	The following financial statements from Dominion Resources, Inc.’s and Virginia Electric and Power Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed on October 25, 2012, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.	X	X

PAGE 82

TABLE OF CONTENTS

Part I. Financial Informationprint Item 1. Financial Statementsprint Note 1. Nature Of Operationsprint Note 2. Significant Accounting Policiesprint Note 3. Dispositionsprint Note 4. Operating Revenueprint Note 5. Income Taxesprint Note 6. Earnings Per Shareprint Note 7. Fair Value Measurementsprint Note 8. Derivatives and Hedge Accounting Activitiesprint Note 9. Investmentsprint Note 10. Regulatory Assets and Liabilitiesprint Note 11. Regulatory Mattersprint Note 12. Asset Retirement Obligationsprint Note 13. Variable Interest Entitiesprint Note 14. Significant Financing Transactionsprint Note 15. Commitments and Contingenciesprint Note 16. Credit Riskprint Note 17. Related Party Transactionsprint Note 18. Employee Benefit Plansprint Note 19. Operating Segmentsprint Item 2. Management S Discussion and Analysisprint Item 4. Controls and Proceduresprint Part II. Other Informationprint Item 1. Legal Proceedingsprint Item 1A. Risk Factorsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 6. Exhibitsprint

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