Edgar Filing: DOMINION RESOURCES INC /VA/

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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, 2013

¨	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, 2013, the latest practicable date for determination, Dominion Resources, Inc. had 580,435,589 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		64
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		78
Item 4.	Controls and Procedures		80

	PART II. Other Information

Item 1.	Legal Proceedings		81
Item 1A.	Risk Factors		81
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		82
Item 6.	Exhibits		83

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

AMR		Automated meter reading program deployed by East Ohio

AOCI		Accumulated other comprehensive income (loss)

Appalachian Gateway Project		DTI project completed in September 2012 to provide approximately 484,000 Dth per day of firm transportation services for new Appalachian gas supplies in West Virginia and southwestern Pennsylvania to an interconnection with Texas Eastern Transmission, LP at Oakford, Pennsylvania

AROs		Asset retirement obligations

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

Blue Racer		Blue Racer Midstream, LLC, a joint venture with Caiman

BOD		Board of Directors

BOEM		Bureau of Ocean Energy Management

BP		BP Wind Energy North America Inc.

Brayton Point		Brayton Point power station, a 1,528 MW power station in Somerset, Massachusetts, with three coal-fired units and one unit fired by natural gas or oil

Brunswick County		Brunswick County power station, a 1,358 MW combined cycle, natural gas-fired power station under construction in Brunswick County, Virginia

CAA		Clean Air Act

Caiman		Caiman Energy II, LLC

CAIR		Clean Air Interstate Rule

Carson-to-Suffolk line		Virginia Power 60-mile 500 kV transmission line in southeastern Virginia

CEO		Chief Executive Officer

CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980

CFO		Chief Financial Officer

CO₂		Carbon dioxide

COL		Combined Construction Permit and Operating License

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

CPCN		Certificate of Public Convenience and Necessity

CSAPR		Cross State Air Pollution Rule

CWA		Clean Water Act

D.C.		District of Columbia

DEI		Dominion Energy, Inc.

DGH		Dominion Gas Holdings, LLC

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

DTI		Dominion Transmission, Inc.

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, a 1,424 MW power station outside Chicago, Illinois, with nine 158 MW natural gas-fired combustion turbines, in which Dominion owned a 50 percent interest (712 MW)

PAGE 3


Abbreviation or Acronym		Definition
Energy Capital Partners		A private equity firm with offices in Short Hills, New Jersey and San Diego, California

Enterprise		Enterprise Product Partners, L.P.

EPA		Environmental Protection Agency

EPS		Earnings per share

ESBWR		General Electric-Hitachi’s Economic Simplified Boiling Water Reactor

Fairless		Fairless power station

FERC		Federal Energy Regulatory Commission

Fitch		Fitch Ratings Ltd.

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

FTRs		Financial transmission rights

GAAP		U.S. generally accepted accounting principles

Gal		Gallon

GHG		Greenhouse gas

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

IDA		Industrial Development Authority

Illinois Gas Contracts		A Dominion Retail natural gas book of business consisting of residential and commercial customers in Illinois

INPO		Institute of Nuclear Power Operations

IRS		Internal Revenue Service

ISO		Independent system operator

ISO-NE		ISO New England

Juniper		Juniper Capital L.P.

Kewaunee		Kewaunee nuclear power station

Kincaid		Kincaid power station, a 1,158 MW power station in Kincaid, Illinois, with two 579 MW coal-fired units

kV		Kilovolt

kWh		Kilowatt-hour

Line TPL-2A		An approximately 11-mile, 30-inch gathering line extending from Tuscarawas County, Ohio to Harrison County, Ohio

Line TL-388		A 37-mile, 24-inch gathering line extending from Texas Eastern, LP in Noble County, Ohio to its terminus at Dominion’s Gilmore Station in Tuscarawas County, Ohio

Line TL-404		An approximately 26-mile, 24- and 30- inch gas gathering pipeline that extends from Wetzel County, West Virginia to Monroe County, Ohio

LNG		Liquefied natural gas

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

MDFA		Massachusetts Development Finance Agency

Meadow Brook-to-Loudoun line		Virginia Power 65-mile 500 kV transmission line that begins in Warren County, Virginia and terminates in Loudoun County, Virginia

Millstone		Millstone nuclear power station

MISO		Midcontinent Independent Transmission System Operator, Inc.

MLP		Master limited partnership

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 in Grant County, West Virginia

NEIL		Nuclear Electric Insurance Limited

NERC		North American Electric Reliability Corporation

NGLs		Natural gas liquids

North Anna		North Anna nuclear power station

North Carolina Commission		North Carolina Utilities Commission

PAGE 4


Abbreviation or Acronym		Definition
Northeast Expansion Project		DTI project completed in November 2012 to provide approximately 200,000 Dth per day of firm transportation services; this project moves supplies from various receipt points in central and southwestern Pennsylvania to a nexus of market pipelines and storage facilities in Leidy, Pennsylvania

NO_x		Nitrogen oxide

NPDES		National Pollutant Discharge Elimination System

NRC		Nuclear Regulatory Commission

NSPS		New Source Performance Standards

ODEC		Old Dominion Electric Cooperative

Order 1000		Order issued by FERC adopting new requirements for transmission planning, cost allocation and development

PADEP		Pennsylvania Department of Environmental Protection

PIPP		Percentage of Income Payment Plan

PIR		Pipeline Infrastructure Replacement program deployed by East Ohio

PJM		PJM Interconnection, L.L.C.

ppb		Parts-per-billion

Regulation Act		Legislation effective July 1, 2007, that amended the Virginia Electric Utility Restructuring Act and fuel factor statute, which legislation is also known as the Virginia Electric Utility Regulation Act

RGGI		Regional Greenhouse Gas Initiative

Rider BW		A rate adjustment clause associated with the recovery of costs related to Brunswick County

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

RSN		Remarketable subordinated note

RTEP		Regional transmission expansion plan

RTO		Regional transmission organization

Salem Harbor		Salem Harbor power station

SEC		Securities and Exchange Commission

Shell		Shell WindEnergy, Inc.

SO₂		Sulfur dioxide

Standard & Poor’s		Standard & Poor’s Ratings Services, a division of McGraw Hill Financial, 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

West Virginia Commission		Public Service Commission of West Virginia

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,
	2013			2012⁽¹⁾			2013			2012⁽¹⁾
(millions, except per share amounts)
Operating Revenue	$	3,432		$	3,332		$	9,935		$	9,734

Operating Expenses
Electric fuel and other energy-related purchases		1,107			1,009			2,933			2,816
Purchased electric capacity		91			86			267			297
Purchased gas		232			191			996			818
Other operations and maintenance		525			1,086			1,876			2,446
Depreciation, depletion and amortization		309			290			909			838
Other taxes		134			119			442			422

Total operating expenses		2,398			2,781			7,423			7,637

Income from operations		1,034			551			2,512			2,097

Other income		86			56			222			174
Interest and related charges		217			197			648			618

Income from continuing operations including noncontrolling interests before income tax expense		903			410			2,086			1,653
Income tax expense		305			143			709			578

Income from continuing operations including noncontrolling interests		598			267			1,377			1,075
Loss from discontinued operations⁽²⁾		(23	)		(52	)		(92	)		(94	)

Net Income Including Noncontrolling Interests		575			215			1,285			981
Noncontrolling Interests		6			6			19			20

Net Income Attributable to Dominion	$	569		$	209		$	1,266		$	961

Amounts Attributable to Dominion:
Income from continuing operations, net of tax	$	592		$	261		$	1,358		$	1,055
Loss from discontinued operations, net of tax		(23	)		(52	)		(92	)		(94	)

Net income attributable to Dominion	$	569		$	209		$	1,266		$	961

Earnings Per Common Share-Basic
Income from continuing operations	$	1.02		$	0.45		$	2.35		$	1.84
Loss from discontinued operations		(0.04	)		(0.09	)		(0.16	)		(0.16	)

Net income attributable to Dominion	$	0.98		$	0.36		$	2.19		$	1.68

Earnings Per Common Share-Diluted
Income from continuing operations	$	1.02		$	0.45		$	2.35		$	1.84
Loss from discontinued operations		(0.04	)		(0.09	)		(0.16	)		(0.16	)

Net income attributable to Dominion	$	0.98		$	0.36		$	2.19		$	1.68

Dividends declared per common share	$	0.5625		$	0.5275		$	1.6875		$	1.5825

(1)	Recast to reflect Brayton Point and Kincaid as discontinued operations, as discussed in Note 3.

(2)	Includes income tax expense of $6 million for the three months ended September 30, 2013 and income tax benefit of $17 million, $43 million and $53 million for the three months ended September 30, 2012 and the nine months ended September 30, 2013 and 2012, 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,
	2013			2012			2013			2012
(millions)
Net income including noncontrolling interests	$	575		$	215		$	1,285		$	981
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities⁽¹⁾		(77	)		(86	)		(45	)		40
Changes in unrealized net gains on investment securities⁽²⁾		38			49			119			110
Changes in unrecognized pension and other postretirement benefit costs⁽³⁾		(12	)		(6	)		216			(4	)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities⁽⁴⁾		(6	)		(20	)		53			(63	)
Net realized gains on investment securities⁽⁵⁾		(10	)		(4	)		(46	)		(18	)
Net pension and other postretirement benefit costs⁽⁶⁾		14			15			44			38

Total other comprehensive income (loss)		(53	)		(52	)		341			103

Comprehensive income including noncontrolling interests		522			163			1,626			1,084
Comprehensive income attributable to noncontrolling interests		6			6			19			20

Comprehensive income attributable to Dominion	$	516		$	157		$	1,607		$	1,064

(1)	Net of $43 million and $57 million tax for the three months ended September 30, 2013 and 2012, respectively, and net of $21 million and $(28) million tax for the nine months ended September 30, 2013 and 2012, respectively.

(2)	Net of $(29) million and $(33) million tax for the three months ended September 30, 2013 and 2012, respectively, and net of $(80) million and $(73) million tax for the nine months ended September 30, 2013 and 2012, respectively.

(3)	Net of $(12) million and $(7) million tax for the three months ended September 30, 2013 and 2012, respectively, and net of $(160) million and $(8) million tax for the nine months ended September 30, 2013 and 2012, respectively.

(4)	Net of $4 million and $12 million tax for the three months ended September 30, 2013 and 2012, respectively, and net of $(35) million and $39 million tax for the nine months ended September 30, 2013 and 2012, respectively

(5)	Net of $5 million and $3 million tax for the three months ended September 30, 2013 and 2012, respectively, and net of $28 million and $12 million tax for the nine months ended September 30, 2013 and 2012, respectively.

(6)	Net of $(9) million and $(6) million tax for the three months ended September 30, 2013 and 2012, respectively, and net of $(29) million and $(23) million tax for the nine months ended September 30, 2013 and 2012, 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, 2013			December 31, 2012⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	287		$	248
Customer receivables (less allowance for doubtful accounts of $27 and $28)		1,499			1,621
Other receivables (less allowance for doubtful accounts of $3 and $4)		103			96
Inventories		1,210			1,259
Derivative assets		689			518
Other		1,422			1,398

Total current assets		5,210			5,140

Investments
Nuclear decommissioning trust funds		3,673			3,330
Investment in equity method affiliates		926			558
Other		277			303

Total investments		4,876			4,191

Property, Plant and Equipment
Property, plant and equipment		46,102			43,364
Property, plant and equipment, VIE		—			957
Accumulated depreciation, depletion and amortization		(14,241	)		(13,548	)

Total property, plant and equipment, net		31,861			30,773

Deferred Charges and Other Assets
Goodwill		3,087			3,130
Regulatory assets		1,478			1,717
Other		1,976			1,887

Total deferred charges and other assets		6,541			6,734

Total assets	$	48,488		$	46,838

(1)	Dominion’s Consolidated Balance Sheet at December 31, 2012 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, 2013			December 31, 2012⁽¹⁾
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	1,132		$	1,363
Securities due within one year, VIE		—			860
Short-term debt		2,145			2,412
Accounts payable		980			1,137
Derivative liabilities		659			510
Other		1,537			1,481

Total current liabilities		6,453			7,763

Long-Term Debt
Long-term debt		16,096			15,478
Junior subordinated notes		1,373			1,373
Remarketable subordinated notes		1,079			—

Total long-term debt		18,548			16,851

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		6,735			5,800
Asset retirement obligations		1,625			1,641
Pension and other postretirement benefit liabilities		1,294			1,831
Regulatory liabilities		1,718			1,514
Other		616			556

Total deferred credits and other liabilities		11,988			11,342

Total liabilities		36,989			35,956

Commitments and Contingencies (see Note 15)

Subsidiary Preferred Stock Not Subject to Mandatory Redemption		257			257

Equity
Common stock - no par⁽²⁾		5,699			5,493
Other paid-in capital		—			162
Retained earnings		6,079			5,790
Accumulated other comprehensive loss		(536	)		(877	)

Total common shareholders’ equity		11,242			10,568

Noncontrolling interest		—			57

Total equity		11,242			10,625

Total liabilities and equity	$	48,488		$	46,838

(1)	Dominion’s Consolidated Balance Sheet at December 31, 2012 has been derived from the audited Consolidated Financial Statements at that date.

(2)	1 billion shares authorized; 580 million shares and 576 million shares outstanding at September 30, 2013 and December 31, 2012, 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,	2013			2012
(millions)
Operating Activities
Net income including noncontrolling interests	$	1,285		$	981
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Impairment of merchant generation assets		48			444
Gains on sales of assets		(118	)		—
Depreciation, depletion and amortization (including nuclear fuel)		1,104			1,080
Deferred income taxes and investment tax credits		601			550
Rate refunds		(5	)		(132	)
Other adjustments		(79	)		(91	)
Changes in:
Accounts receivable		98			371
Inventories		(63	)		35
Deferred fuel and purchased gas costs, net		85			332
Prepayments		46			(72	)
Accounts payable		(144	)		(216	)
Accrued interest, payroll and taxes		(38	)		1
Margin deposit assets and liabilities		(27	)		126
Other operating assets and liabilities		157			53

Net cash provided by operating activities		2,950			3,462

Investing Activities
Plant construction and other property additions (including nuclear fuel)		(2,978	)		(2,884	)
Proceeds from sales of assets		595			—
Proceeds from sales of securities		1,260			1,040
Purchases of securities		(1,278	)		(1,047	)
Restricted cash equivalents		23			92
Other		30			15

Net cash used in investing activities		(2,348	)		(2,784	)

Financing Activities
Repayment of short-term debt, net		(267	)		(433	)
Issuance of long-term debt		2,935			1,500
Repayment of long-term debt, including redemption premiums		(1,214	)		(1,037	)
Repayment of junior subordinated notes		(258	)		—
Acquisition of Juniper noncontrolling interest in Fairless		(923	)		—
Issuance of common stock		206			197
Common dividend payments		(976	)		(906	)
Subsidiary preferred dividend payments		(12	)		(12	)
Other		(54	)		(8	)

Net cash used in financing activities		(563	)		(699	)

Increase (decrease) in cash and cash equivalents		39			(21	)
Cash and cash equivalents at beginning of period		248			102

Cash and cash equivalents at end of period	$	287		$	81

Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	271		$	328
Contribution of assets in exchange for additional ownership interest in Blue Racer		473			—

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,
	2013		2012		2013		2012
(millions)
Operating Revenue	$	2,059	$	2,086	$	5,550	$	5,596

Operating Expenses
Electric fuel and other energy-related purchases		651		634		1,749		1,850
Purchased electric capacity		91		86		267		296
Other operations and maintenance:
Affiliated suppliers		83		91		238		256
Other		273		278		792		861
Depreciation and amortization		218		203		636		579
Other taxes		64		48		196		179

Total operating expenses		1,380		1,340		3,878		4,021

Income from operations		679		746		1,672		1,575

Other income		19		25		71		65
Interest and related charges		93		97		270		297

Income before income tax expense		605		674		1,473		1,343
Income tax expense		218		259		534		513

Net Income		387		415		939		830
Preferred dividends		4		4		12		12

Balance available for common stock	$	383	$	411	$	927	$	818

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,
	2013			2012			2013			2012
(millions)
Net income	$	387		$	415		$	939		$	830
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities⁽¹⁾		1			(2	)		4			(5	)
Changes in unrealized net gains on nuclear decommissioning trust funds⁽²⁾		4			4			12			11
Amounts reclassified to net income:
Net derivative losses-hedging activities⁽³⁾		1			1			—			2
Net realized gains on nuclear decommissioning trust funds⁽⁴⁾		(2	)		—			(2	)		(1	)

Other comprehensive income		4			3			14			7

Comprehensive income	$	391		$	418		$	953		$	837

(1)	Net of $(1) million and $1 million tax for the three months ended September 30, 2013 and 2012, respectively, and net of $(3) million and $3 million tax for the nine months ended September 30, 2013 and 2012, respectively.

(2)	Net of $(2) million and $(4) million tax for the three months ended September 30, 2013 and 2012, respectively, and net of $(7) million and $(7) million tax for the nine months ended September 30, 2013 and 2012, respectively.

(3)	Net of $— million and $— million tax for the three months ended September 30, 2013 and 2012, respectively, and net of $— million and $(2) million tax for the nine months ended September 30, 2013 and 2012, respectively.

(4)	Net of $— million and $— million tax for the three months ended September 30, 2013 and 2012, respectively, and net of $1 million and $1 million tax for the nine months ended September 30, 2013 and 2012, 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, 2013			December 31, 2012⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	51		$	28
Customer receivables (less allowance for doubtful accounts of $10 at both dates)		906			849
Other receivables (less allowance for doubtful accounts of $2 and $3)		59			51
Inventories (average cost method)		804			789
Prepayments		28			23
Other		271			241

Total current assets		2,119			1,981

Investments
Nuclear decommissioning trust funds		1,668			1,515
Other		14			14

Total investments		1,682			1,529

Property, Plant and Equipment
Property, plant and equipment		32,249			30,631
Accumulated depreciation and amortization		(10,481	)		(10,014	)

Total property, plant and equipment, net		21,768			20,617

Deferred Charges and Other Assets
Intangible assets, net		187			181
Regulatory assets		420			396
Other		134			107

Total deferred charges and other assets		741			684

Total assets	$	26,310		$	24,811

(1)	Virginia Power’s Consolidated Balance Sheet at December 31, 2012 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, 2013		December 31, 2012⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	58	$	418
Short-term debt		485		992
Accounts payable		392		430
Payables to affiliates		87		67
Affiliated current borrowings		—		435
Accrued interest, payroll and taxes		354		204
Other		413		461

Total current liabilities		1,789		3,007

Long-Term Debt		7,981		6,251

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		4,112		3,879
Asset retirement obligations		727		705
Regulatory liabilities		1,471		1,285
Other		263		194

Total deferred credits and other liabilities		6,573		6,063

Total liabilities		16,343		15,321

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		1,113		1,113
Retained earnings		2,820		2,357
Accumulated other comprehensive income		39		25

Total common shareholder’s equity		9,710		9,233

Total liabilities and shareholder’s equity	$	26,310	$	24,811

(1)	Virginia Power’s Consolidated Balance Sheet at December 31, 2012 has been derived from the audited Consolidated Financial Statements at that date.

(2)	500,000 shares authorized; 274,723 shares outstanding at September 30, 2013 and December 31, 2012.

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,	2013			2012
(millions)
Operating Activities
Net income	$	939		$	830
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		758			687
Deferred income taxes and investment tax credits		243			331
Rate refunds		(5	)		(132	)
Other adjustments		(49	)		(47	)
Changes in:
Accounts receivable		(65	)		(2	)
Affiliated accounts payable		20			40
Inventories		(15	)		40
Deferred fuel expenses		47			321
Accounts payable		(10	)		28
Accrued interest, payroll and taxes		150			70
Other operating assets and liabilities		23			121

Net cash provided by operating activities		2,036			2,287

Investing Activities
Plant construction and other property additions		(1,794	)		(1,402	)
Purchases of nuclear fuel		(108	)		(142	)
Purchases of securities		(501	)		(491	)
Proceeds from sales of securities		464			481
Restricted cash equivalents		—			21
Other		(9	)		(18	)

Net cash used in investing activities		(1,948	)		(1,551	)

Financing Activities
Repayment of short-term debt, net		(507	)		(789	)
Repayment of affiliated current borrowings, net		(435	)		—
Issuance of long-term debt		1,835			450
Repayment of long-term debt		(462	)		(10	)
Common dividend payments		(463	)		(379	)
Preferred dividend payments		(12	)		(12	)
Other		(21	)		(4	)

Net cash used in financing activities		(65	)		(744	)

Increase (decrease) in cash and cash equivalents		23			(8	)
Cash and cash equivalents at beginning of period		28			29

Cash and cash equivalents at end of period	$	51		$	21

Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	137		$	136

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, 2012 and their Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013.

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, 2013, their results of operations for the three and nine months ended September 30, 2013 and 2012 and their cash flows for the nine months ended September 30, 2013 and 2012. 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 2012 Consolidated Financial Statements and Notes have been reclassified to conform to the 2013 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

Sale of Illinois Gas Contracts

In June 2013, Dominion completed the sale of Illinois Gas Contracts. The sales price was approximately $32 million, subject to post-closing adjustments. The sale resulted in a gain of approximately $29 million ($18 million after-tax) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in Dominion’s Consolidated Statement of Income. The sale of Illinois Gas Contracts did not qualify for discontinued operations classification as it is not considered a component under applicable accounting guidance.

Sale of Brayton Point, Kincaid and Equity Method Investment in Elwood

In March 2013, Dominion entered into an agreement with Energy Capital Partners to sell Brayton Point, Kincaid, and its equity method investment in Elwood.

In the first and second quarters of 2013, Brayton Point’s and Kincaid’s assets and liabilities to be disposed of were classified as held for sale and adjusted to their estimated fair value less cost to sell, resulting in impairment charges totaling $48 million ($28 million after-tax), which are included in discontinued operations in Dominion’s Consolidated Statements of Income. In both periods, Dominion used the market approach to estimate the fair value of Brayton Point’s and Kincaid’s long-lived assets. These were considered Level 2 fair value measurements given that they were based on the agreed-upon sales price.

Dominion’s 50% interest in Elwood was an equity method investment and therefore, in accordance with applicable accounting guidance, the carrying amount of this investment was not classified as held for sale nor were the equity earnings from this investment reported as discontinued operations.

PAGE 16

In August 2013, Dominion completed the sale and received proceeds of approximately $465 million, net of transaction costs. The sale resulted in a $35 million ($25 million after-tax) gain attributable to its equity method investment in Elwood, which is included in other income in Dominion’s Consolidated Statement of Income, which was partially offset by a $17 million ($18 million after-tax) loss attributable to Brayton Point and Kincaid, which includes a $16 million write-off of goodwill and is reflected in loss from discontinued operations in Dominion’s Consolidated Statement of Income.

The following table presents selected information regarding the results of operations of Brayton Point and Kincaid, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
(millions)
Operating revenue	$	87		$	77		$	304		$	191
Loss before income taxes		(17	)		(50	)		(135	)⁽¹⁾		(98	)

(1)	Includes $64 million of charges related to the early redemption of Brayton Point and Kincaid debt. See Note 14 in this report for more information.

Sale of Salem Harbor and State Line

In the third quarter of 2012, Dominion completed the sale of Salem Harbor. During the second quarter of 2012, Dominion completed the sale of 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:


	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
(millions)
Operating revenue	$	5		$	57
Loss before income taxes		(19	)		(49	)

PAGE 17

Note 4. Operating Revenue

The Companies’ operating revenue consists of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
(millions)
Dominion
Electric sales:
Regulated	$	2,023	$	2,046	$	5,471	$	5,495
Nonregulated		704		661		1,907		1,930
Gas sales:
Regulated		32		34		213		166
Nonregulated		159		177		712		740
Gas transportation and storage		329		297		1,156		1,007
Other		185		117		476		396

Total operating revenue	$	3,432	$	3,332	$	9,935	$	9,734

Virginia Power
Regulated electric sales	$	2,023	$	2,046	$	5,471	$	5,495
Other		36		40		79		101

Total operating revenue	$	2,059	$	2,086	$	5,550	$	5,596

Note 5. Income Taxes

In December 2011, the IRS issued temporary regulations that provide guidance to taxpayers on the treatment of amounts paid to acquire, produce or improve tangible property and of dispositions of such property, including whether expenditures should be deducted as repairs or capitalized and depreciated on tax returns. Upon issuance, the temporary regulations were generally to be effective for expenditures made on or after January 1, 2012. However, in December 2012, in response to public comments received, the IRS amended the temporary regulations to postpone the effective date until January 1, 2014.

In September 2013, the IRS withdrew the December 2011 temporary regulations and issued final regulations. The final regulations include a number of safe harbor tax accounting methods which a taxpayer may choose to elect and, if adopted, will not be challenged by the IRS. In addition, the IRS reissued certain temporary regulations that were also issued concurrently as proposed regulations regarding property dispositions. The final regulations are effective for tax years beginning on or after January 1, 2014. Although changes in tax accounting methods would be effective prospectively, implementation of certain changes will require a calculation of the cumulative effect of the change on prior years. Beginning with the year of the change, this cumulative effect is includible in taxable income over a period assumed to be four years, pending the issuance of IRS procedural guidance.

Dominion and Virginia Power have evaluated tax accounting method changes that may be elected or required by the final regulations. At September 30, 2013, $13 million of deferred tax liabilities have been classified as current in the Companies’ Consolidated Balance Sheets, representing cumulative adjustment amounts expected to be reflected in income for tax purposes during the nine months ending September 30, 2014. Tax accounting method changes in 2014 are not expected to materially affect the Companies’ cash flows, results of operations or financial condition.

PAGE 18

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,	2013			2012			2013			2012
U.S. statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		2.4			4.4			2.8			3.9
Investment and production tax credits		(1.8	)		(0.6	)		(0.2	)		—
Valuation allowances		—			(0.9	)		—			—
AFUDC - equity		(0.7	)		(0.9	)		(1.1	)		(0.8	)
Other, net		(0.9	)		(2.1	)		(0.3	)		0.1

Effective tax rate		34.0	%		34.9	%		36.2	%		38.2	%

Dominion’s and Virginia Power’s 2013 state income tax expense reflects changes in the amount of income apportioned among states.

Dominion’s effective tax rate in 2012 reflects a $20 million reduction of 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 concluded that it was more likely than not that the tax benefit of the operating losses would be realized. Significant assumptions included 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 would significantly influence the extent to which Fairless is dispatched by PJM. In August 2013, Dominion purchased Fairless from Juniper per the terms of the lease agreement. See Note 13 in this report for more information.

See Note 5 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2012, for a discussion of the Companies’ unrecognized tax benefits. During the nine months ended September 30, 2013, Dominion’s and Virginia Power’s unrecognized tax benefits changed as follows:


	Dominion			Virginia Power
(millions)
Balance at January 1, 2013	$	293		$	57
Increases - prior period positions		14			12
Decreases - prior period positions		(91	)		(42	)
Current period positions		21			7
Settlements		(2	)		(2	)
Expiration of statutes of limitations		(4	)		—

Balance at September 30, 2013	$	231		$	32

Discontinued Operations

Dominion’s effective tax rate for 2013 reflects the impact of goodwill written off in the sale of Kincaid and Brayton Point that is not deductible for tax purposes.

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,
	2013		2012		2013		2012
(millions, except EPS)
Net income attributable to Dominion	$	569	$	209	$	1,266	$	961

Average shares of common stock outstanding - Basic		579.4		573.8		578.1		572.1
Net effect of dilutive securities⁽¹⁾		0.7		0.9		0.7		1.1

Average shares of common stock outstanding - Diluted		580.1		574.7		578.8		573.2

Earnings Per Common Share - Basic	$	0.98	$	0.36	$	2.19	$	1.68
Earnings Per Common Share - Diluted	$	0.98	$	0.36	$	2.19	$	1.68

(1)	Dilutive securities consist primarily of contingently convertible senior notes. See Note 14 in this report for more information.

PAGE 19

Dominion’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013 are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2013. See Note 14 in this report for more information. There were no potentially dilutive securities excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2012.

PAGE 20

Note 7. Accumulated Other Comprehensive Income

The following table presents Dominion’s changes in AOCI by component, net of tax:


	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Unrecognized pension and other postretirement benefit costs			Total
(millions)
Three Months Ended September 30, 2013
Beginning balance	$	(31	)	$	371		$	(823	)	$	(483	)
Other comprehensive income before reclassifications: gains (losses)		(77	)		38			(12	)		(51	)
Amounts reclassified from accumulated other comprehensive income⁽¹⁾: (gains) losses		(6	)		(10	)		14			(2	)

Net current-period other comprehensive income (loss)		(83	)		28			2			(53	)

Ending balance	$	(114	)	$	399		$	(821	)	$	(536	)

Nine Months Ended September 30, 2013
Beginning balance	$	(122	)	$	326		$	(1,081	)	$	(877	)
Other comprehensive income before reclassifications: gains (losses)		(45	)		119			216			290
Amounts reclassified from accumulated other comprehensive income⁽¹⁾: (gains) losses		53			(46	)		44			51

Net current-period other comprehensive income (loss)		8			73			260			341

Ending balance	$	(114	)	$	399		$	(821	)	$	(536	)

(1)	See table below for details about these reclassifications.

PAGE 21

The following table presents Dominion’s reclassifications out of AOCI by component:


Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Three Months Ended September 30, 2013
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(24	)	Operating revenue
		5		Purchased gas
		3		Electric fuel and other energy-related purchases
Interest rate contracts		6		Interest and related charges

		(10	)
Tax		4		Income tax expense

	$	(6	)

Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(16	)	Other income
Impairment		1		Other income

		(15	)
Tax		5		Income tax expense

	$	(10	)

Unrecognized pension and other postretirement benefit costs:
Actuarial losses	$	23		Other operations and maintenance

		23
Tax		(9	)	Income tax expense

	$	14

Nine Months Ended September 30, 2013
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	31		Operating revenue
		39		Purchased gas
		6		Electric fuel and other energy-related purchases
Interest rate contracts		12		Interest and related charges

		88
Tax		(35	)	Income tax expense

	$	53

Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(80	)	Other income
Impairment		6		Other income

		(74	)
Tax		28		Income tax expense

	$	(46	)

Unrecognized pension and other postretirement benefit costs:
Prior service costs	$	(6	)	Other operations and maintenance
Actuarial losses		79		Other operations and maintenance

		73
Tax		(29	)	Income tax expense

	$	44

PAGE 22

Note 8. Fair Value Measurements

Dominion’s and Virginia Power’s fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in their Annual Report on Form 10-K for the year ended December 31, 2012. See Note 9 in this report for further information about their derivatives and hedge accounting activities.

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, mean reversions, 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, forward market prices, 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 and Virginia Power’s quantitative information about Level 3 fair value measurements. The range and weighted average are presented in dollars for market price inputs, years for mean reversion speeds, and percentages for price volatility, price correlations, load shaping, and usage factors.


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

At September 30, 2013
Assets:
Physical and Financial Forwards and Futures:
Natural Gas⁽²⁾	$	10	Discounted Cash Flow		Market Price (per Dth)	⁽⁴⁾	(1) - 5		2
Electricity		9	Discounted Cash Flow		Market Price (per MWh)	⁽⁴⁾	31 - 77		44
FTRs⁽³⁾		1	Discounted Cash Flow		Market Price (per MWh)	⁽⁴⁾	(1) - 6		0
Liquids		12	Discounted Cash Flow		Market Price (per Gal)	⁽⁴⁾	0 - 3		1
Physical and Financial Options:
Natural Gas		7	Option Model		Market Price (per Dth)	⁽⁴⁾	3 - 5		4
					Price Volatility	⁽⁵⁾	19% - 30%		24	%
					Price Correlation	⁽⁶⁾	(9)% - 100%		36	%
					Mean Reversion	⁽⁷⁾	0 - 58		4
Full Requirements Contracts:
Electricity		13	Discounted Cash Flow		Market Price (per MWh)	⁽⁴⁾	10 - 403⁽¹⁰⁾		34
					Load Shaping	⁽⁸⁾	0% - 10%		7	%
					Usage Factor	⁽⁹⁾	11% - 15%		14	%

Total assets	$	52

Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas⁽²⁾	$	16	Discounted Cash Flow		Market Price (per Dth)	⁽⁴⁾	(1) - 5		1
Electricity		6	Discounted Cash Flow		Market Price (per MWh)	⁽⁴⁾	23 - 86		50
FTRs⁽³⁾		16	Discounted Cash Flow		Market Price (per MWh)	⁽⁴⁾	(4) - 6		1
Liquids		8	Discounted Cash Flow		Market Price (per Gal)	⁽⁴⁾	1 - 3		2
Physical and Financial Options:
Natural Gas		10	Option Model		Market Price (per Dth)	⁽⁴⁾	3 - 10		5
					Price Volatility	⁽⁵⁾	19% - 30%		23	%
					Price Correlation	⁽⁶⁾	(9)% - 100%		36	%
					Mean Reversion	⁽⁷⁾	0 - 58		4

Total liabilities	$	56

PAGE 23

(1)	Averages weighted by volume.

(2)	Includes basis.

(3)	Information represents Virginia Power’s quantitative information about Level 3 fair value measurements.

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

(5)	Represents volatilities unrepresented in published markets.

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

(7)	Represents mean-reverting property in price simulation modeling.

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

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

(10)	The range in market prices is the result of large variability in hourly power prices during peak and off-peak hours.

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)
Mean Reversion	Buy	Increase (decrease)	Loss (gain)
Mean Reversion	Sell	Increase (decrease)	Gain (loss)
Load Shaping	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 June 2013, Dominion purchased certain natural gas infrastructure facilities that were previously leased from third parties. The purchase price was based on terms in the lease, which exceeded current market pricing. As a result of the purchase price and expected losses, Dominion recorded an impairment charge of $49 million ($29 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write down the long-lived assets to their estimated fair values 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 the assets in this impairment test. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs, including estimates of future production and other commodity prices.

See Note 3 for non-recurring fair value measurements related to Brayton Point and Kincaid.

PAGE 24

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, 2013
Assets:
Derivatives:
Commodity	$	6	$	713	$	52	$	771
Interest rate		—		114		—		114
Investments⁽¹⁾:
Equity securities:
U.S.:
Large cap		2,211		—		—		2,211
Other		74		—		—		74
Non-U.S.:
Large cap		11		—		—		11
Fixed income:
Corporate debt instruments		—		352		—		352
U.S. Treasury securities and agency debentures		414		168		—		582
State and municipal		—		342		—		342
Other		—		4		—		4
Cash equivalents and other		9		80		—		89
Restricted cash equivalents		—		10		—		10

Total assets	$	2,725	$	1,783	$	52	$	4,560

Liabilities:
Derivatives:
Commodity	$	5	$	721	$	56	$	782
Interest rate		—		11		—		11

Total liabilities	$	5	$	732	$	56	$	793

At December 31, 2012
Assets:
Derivatives:
Commodity	$	12	$	639	$	84	$	735
Interest rate		—		93		—		93
Investments⁽¹⁾:
Equity securities:
U.S.:
Large cap		1,973		—		—		1,973
Other		59		—		—		59
Non-U.S.:
Large cap		12		—		—		12
Fixed income:
Corporate debt instruments		—		325		—		325
U.S. Treasury securities and agency debentures		391		152		—		543
State and municipal		—		315		—		315
Other		—		7		—		7
Cash equivalents and other		13		67		—		80
Restricted cash equivalents		—		33		—		33

Total assets	$	2,460	$	1,631	$	84	$	4,175

Liabilities:
Derivatives:
Commodity	$	8	$	528	$	59	$	595
Interest rate		—		66		—		66

Total liabilities	$	8	$	594	$	59	$	661

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

PAGE 25

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,
	2013			2012			2013			2012
(millions)
Beginning balance	$	2		$	155		$	25		$	(71	)
Total realized and unrealized gains (losses):
Included in earnings		(1	)		(8	)		1			(31	)
Included in other comprehensive income (loss)		(25	)		(48	)		11			124
Included in regulatory assets/liabilities		10			2			(17	)		30
Settlements		3			3			(23	)		54
Transfers out of Level 3		7			(1	)		(1	)		(3	)

Ending balance	$	(4	)	$	103		$	(4	)	$	103

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	$	2		$	(15	)	$	—		$	25

PAGE 26

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, 2013
Total gains (losses) included in earnings	$	5		$	(6	)	$	(1	)
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		2			—			2

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	)

Nine Months Ended September 30, 2013
Total gains (losses) included in earnings	$	12		$	(11	)	$	1
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		—			—			—

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

PAGE 27

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, 2013
Assets:
Derivatives:
Commodity	$	—	$	1	$	1	$	2
Interest rate		—		33		—		33
Investments⁽¹⁾:
Equity securities:
U.S.:
Large cap		939		—		—		939
Other		33		—		—		33
Fixed income:
Corporate debt instruments		—		197		—		197
U.S. Treasury securities and agency debentures		146		63		—		209
State and municipal		—		160		—		160
Cash equivalents and other		—		24		—		24
Restricted cash equivalents		—		10		—		10

Total assets	$	1,118	$	488	$	1	$	1,607

Liabilities:
Derivatives:
Commodity	$	—	$	4	$	16	$	20

Total liabilities	$	—	$	4	$	16	$	20

At December 31, 2012
Assets:
Derivatives:
Commodity	$	—	$	1	$	5	$	6
Investments⁽¹⁾:
Equity securities:
U.S.:
Large cap		779		—		—		779
Other		27		—		—		27
Fixed income:
Corporate debt instruments		—		196		—		196
U.S. Treasury securities and agency debentures		168		66		—		234
State and municipal		—		118		—		118
Other		—		1		—		1
Cash equivalents and other		7		31		—		38
Restricted cash equivalents		—		10		—		10

Total assets	$	981	$	423	$	5	$	1,409

Liabilities:
Derivatives:
Commodity	$	—	$	6	$	3	$	9
Interest rate		—		25		—		25

Total liabilities	$	—	$	31	$	3	$	34

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

PAGE 28

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,
	2013			2012			2013			2012
(millions)
Beginning balance	$	(25	)	$	1		$	2		$	(28	)
Total realized and unrealized gains (losses):
Included in earnings		(4	)		2			(9	)		(44	)
Included in regulatory assets/liabilities		10			2			(17	)		31
Settlements		4			(2	)		9			44

Ending balance	$	(15	)	$	3		$	(15	)	$	3

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, 2013 and 2012. There were no unrealized gains or 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, 2013 and 2012.

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, which 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, 2013				December 31, 2012
	Carrying Amount		Estimated Fair Value⁽¹⁾		Carrying Amount		Estimated Fair Value⁽¹⁾
(millions)
Dominion
Long-term debt, including securities due within one year⁽²⁾	$	17,228	$	18,899	$	16,841	$	19,898
Securities due within one year, VIE⁽³⁾		—		—		860		864
Junior subordinated notes⁽³⁾		1,373		1,397		1,373		1,430
Remarketable subordinated notes⁽³⁾		1,079		1,175		—		—
Subsidiary preferred stock⁽⁴⁾		257		258		257		255

Virginia Power
Long-term debt, including securities due within one year⁽²⁾	$	8,039	$	8,975	$	6,669	$	8,270
Preferred stock⁽⁴⁾		257		258		257		255

(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)	Carrying amount includes amounts which represent the unamortized discount and premium. At September 30, 2013 and December 31, 2012, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt of approximately $56 million and $93 million, respectively.

(3)	Carrying amount includes amounts which represent the unamortized discount or premium.

(4)	Carrying amount includes deferred issuance expenses of $2 million at September 30, 2013 and December 31, 2012.

Note 9. 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, 2012. See Note 8 in this report for further information about fair value measurements and associated valuation methods for derivatives.

PAGE 29

Derivative assets and liabilities are presented gross on Dominion’s and Virginia Power’s Consolidated Balance Sheets. Dominion’s and Virginia Power’s derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions.

In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and in some cases other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on Dominion’s and Virginia Power’s Consolidated Balance Sheets, as well as letters of credit and other forms of security, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure.

Dominion

The tables below present Dominion’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:


	September 30, 2013						December 31, 2012
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	114	$	—	$	114	$	93	$	—	$	93
Commodity contracts:
Over-the-counter		190		—		190		290		—		290
Exchange		568		—		568		416		—		416

Total derivatives, subject to a master netting or similar arrangement		872		—		872		799		—		799
Total derivatives, not subject to a master netting or similar arrangement		13		—		13		29		—		29

Total⁽¹⁾	$	885	$	—	$	885	$	828	$	—	$	828

(1)

At September 30, 2013, the total derivative asset balance contains $689 million of current assets, which is presented in current derivative assets, in Dominion’s Consolidated Balance Sheet, and $196 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $518 million of current assets, which is presented in current derivative assets in Dominion’s Consolidated Balance Sheet and $310 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet.

PAGE 30


			September 30, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	114	$	11	$	—	$	103	$	93	$	19	$	—	$	74
Commodity contracts:
Over-the-counter		190		78		—		112		290		97		—		193
Exchange		568		563		3		2		416		350		4		62

Total	$	872	$	652	$	3	$	217	$	799	$	466	$	4	$	329


	September 30, 2013						December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	11	$	—	$	11	$	66	$	—	$	66
Commodity contracts:
Over-the-counter		162		—		162		191		—		191
Exchange		617		—		617		393		—		393

Total derivatives, subject to a master netting or similar arrangement		790		—		790		650		—		650
Total derivatives, not subject to a master netting or similar arrangement		3		—		3		11		—		11

Total⁽¹⁾	$	793	$	—	$	793	$	661	$	—	$	661

(1)

At September 30, 2013, the total derivative liability balance contains $659 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet, and $134 million of noncurrent liabilities, which is presented in the other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $510 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet and $151 million of noncurrent liabilities, which is presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet.

PAGE 31


			September 30, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	11	$	11	$	—	$	—	$	66	$	19	$	—	$	47
Commodity contracts:
Over-the-counter		162		78		17		67		191		97		20		74
Exchange		617		563		54		—		393		350		43		—

Total	$	790	$	652	$	71	$	67	$	650	$	466	$	63	$	121

The following table presents the volume of Dominion’s derivative activity as of September 30, 2013. 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⁾		149		27
Basis		529		379
Electricity (MWh):
Fixed price⁽¹⁾		17,059,889		15,411,998
FTRs		64,859,720		689,289
Capacity (MW)		133,650		18,300
Liquids (Gal)⁽²⁾		152,418,000		35,700,000
Interest rate	$	2,400,000,000	$	1,150,000,000

(1)	Includes options.

(2)	Includes NGLs and oil.

For the three and nine months ended September 30, 2013 and 2012, 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, 2013:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(7	)	$	(6	)		31 months
Electricity		6			(9	)		39 months
Other		4			2			32 months
Interest rate		(117	)		(21	)		367 months

Total	$	(114	)	$	(34	)

PAGE 32

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 33

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, 2013
ASSETS
Current Assets
Commodity	$	53	$	546	$	599
Interest rate		90		—		90

Total current derivative assets		143		546		689

Noncurrent Assets
Commodity		70		102		172
Interest rate		24		—		24

Total noncurrent derivative assets⁽¹⁾		94		102		196

Total derivative assets	$	237	$	648	$	885

LIABILITIES
Current Liabilities
Commodity	$	64	$	584	$	648
Interest rate		11		—		11

Total current derivative liabilities		75		584		659

Noncurrent Liabilities
Commodity		47		87		134

Total noncurrent derivative liabilities⁽²⁾		47		87		134

Total derivative liabilities	$	122	$	671	$	793

December 31, 2012
ASSETS
Current Assets
Commodity	$	103	$	379	$	482
Interest rate		36		—		36

Total current derivative assets		139		379		518

Noncurrent Assets
Commodity		130		123		253
Interest rate		57		—		57

Total noncurrent derivative assets⁽¹⁾		187		123		310

Total derivative assets	$	326	$	502	$	828

LIABILITIES
Current Liabilities
Commodity	$	103	$	341	$	444
Interest rate		66		—		66

Total current derivative liabilities		169		341		510

Noncurrent Liabilities
Commodity		58		93		151

Total noncurrent derivative liabilities⁽²⁾		58		93		151

Total derivative liabilities	$	227	$	434	$	661

(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 34

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, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	24
Purchased Gas					(5	)
Electric fuel and other energy-related purchases					(3	)

Total commodity	$	(110	)	$	16		$	4

Interest rate⁽³⁾		(10	)		(6	)		14

Total	$	(120	)	$	10		$	18

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

Nine Months Ended September 30, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	(31	)
Purchased gas					(39	)
Electric fuel and other energy-related purchases					(6	)

Total commodity	$	(137	)	$	(76	)	$	3

Interest rate⁽³⁾		71			(12	)		66

Total	$	(66	)	$	(88	)	$	69

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	)

(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 35


	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	2013			2012		2013			2012
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	3		$	5	$	—		$	108
Purchased gas		(3	)		3		(11	)		(2	)
Electric fuel and other energy-related purchases		(12	)		3		(20	)		(33	)
Interest rate⁽²⁾		—			10		—			17

Total	$	(12	)	$	21	$	(31	)	$	90

(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 tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:


	September 30, 2013						December 31, 2012
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	33	$	—	$	33	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		2		—		2		6		—		6

Total derivatives, subject to a master netting or similar arrangement		35		—		35		6		—		6
Total derivatives, not subject to a master netting or similar arrangement		—		—		—		—		—		—

Total⁽¹⁾	$	35	$	—	$	35	$	6	$	—	$	6

(1)

At September 30, 2013, the total derivative asset balance contains $35 million of current assets, which is presented in other current assets in Virginia Power’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $6 million of current assets, which is presented in other current assets in Virginia Power’s Consolidated Balance Sheet.

PAGE 36


			September 30, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	33	$	—	$	—	$	33	$	—	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		2		2		—		—		6		3		—		3

Total	$	35	$	2	$	—	$	33	$	6	$	3	$	—	$	3


	September 30, 2013						December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	25	$	—	$	25
Commodity contracts:
Over-the-counter		19		—		19		7		—		7
Exchange		1		—		1		2		—		2

Total derivatives, subject to a master netting or similar arrangement		20		—		20		34		—		34
Total derivatives, not subject to a master netting or similar arrangement		—		—		—		—		—		—

Total⁽¹⁾	$	20	$	—	$	20	$	34	$	—	$	34

(1)

At September 30, 2013, the total derivative liability balance contains $20 million of current liabilities, which is presented in other current liabilities in Virginia Power’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $33 million of current liabilities, which is presented in other current liabilities in Virginia Power’s Consolidated Balance Sheet and $1 million of noncurrent derivative liabilities, which is presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheet.

PAGE 37


			September 30, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	—	$	25	$	—	$	—	$	25
Commodity contracts:
Over-the-counter		19		2		14		3		7		3		—		4
Exchange		1		—		1		—		2		—		2		—

Total	$	20	$	2	$	15	$	3	$	34	$	3	$	2	$	29

The following table presents the volume of Virginia Power’s derivative activity as of September 30, 2013. 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		9		—
Basis		5		—
Electricity (MWh):
Fixed price		511,200		—
FTRs		63,408,139		—
Capacity (MW)		121,500		18,300
Interest rate	$	600,000,000	$	—

PAGE 38

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 under Hedge Accounting		Total Fair Value
(millions)
September 30, 2013
ASSETS
Current Assets
Commodity	$	1	$	1	$	2
Interest rate		33		—		33

Total current derivative assets⁽¹⁾		34		1		35

Total derivative assets	$	34	$	1	$	35

LIABILITIES
Current Liabilities
Commodity	$	3	$	17	$	20

Total current derivative liabilities⁽²⁾		3		17		20

Total derivative liabilities	$	3	$	17	$	20

December 31, 2012
ASSETS
Current Assets
Commodity	$	1	$	5	$	6

Total current derivative assets⁽¹⁾		1		5		6

Total derivative assets	$	1	$	5	$	6

LIABILITIES
Current Liabilities
Commodity	$	5	$	3	$	8
Interest rate		25		—		25

Total current derivative liabilities⁽²⁾		30		3		33

Noncurrent Liabilities
Commodity		1		—		1

Total noncurrent derivative liabilities⁽³⁾		1		—		1

Total derivative liabilities	$	31	$	3	$	34

(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 39

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, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)

Total commodity	$	1		$	(1	)	$	4

Interest rate⁽³⁾		1			—			14

Total	$	2		$	(1	)	$	18

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

Nine Months Ended September 30, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	—

Total commodity	$	—		$	—		$	3

Interest rate⁽³⁾		7			—			66

Total	$	7		$	—		$	69

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	)

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

PAGE 40


	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	2013			2012		2013			2012
(millions)
Derivative Type and Location of Gains (Losses)
Commodity⁽²⁾	$	(4	)	$	3	$	(8	)	$	(43	)
Interest rate⁽³⁾		—			1		—			—

Total	$	(4	)	$	4	$	(8	)	$	(43	)

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

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

Note 10. 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 $100 million and $95 million at September 30, 2013 and December 31, 2012, respectively. Cost method investments held in Dominion’s rabbi trusts totaled $10 million and $14 million at September 30, 2013 and December 31, 2012, respectively.

PAGE 41

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, 2013
Marketable equity securities:
U.S.:
Large Cap	$	1,176	$	999	$	—		$	2,175
Other		48		20		—			68
Marketable debt securities:
Corporate bonds		339		17		(4	)		352
U.S. Treasury securities and agency debentures		571		10		(7	)		574
State and municipal		299		13		(4	)		308
Other		4		—		—			4
Cost method investments		103		—		—			103
Cash equivalents and other⁽²⁾		89		—		—			89

Total	$	2,629	$	1,059	$	(15	)⁽³⁾	$	3,673

December 31, 2012
Marketable equity securities:
U.S.:
Large Cap	$	1,210	$	732	$	—		$	1,942
Other		40		13		—			53
Marketable debt securities:
Corporate bonds		295		30		—			325
U.S. Treasury securities and agency debentures		523		19		(2	)		540
State and municipal		248		26		—			274
Other		6		1		—			7
Cost method investments		117		—		—			117
Cash equivalents and other⁽²⁾		72		—		—			72

Total	$	2,511	$	821	$	(2	)⁽³⁾	$	3,330

(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 $6 million at September 30, 2013 and December 31, 2012, respectively.

(3)	The fair value of securities in an unrealized loss position was $487 million and $195 million at September 30, 2013 and December 31, 2012, respectively.

PAGE 42

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2013 by contractual maturity is as follows:


	Amount
(millions)
Due in one year or less	$	138
Due after one year through five years		341
Due after five years through ten years		358
Due after ten years		401

Total	$	1,238

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,
	2013		2012		2013		2012
(millions)
Proceeds from sales	$	398	$	276	$	1,260	$	1,040
Realized gains⁽¹⁾		29		15		121		71
Realized losses⁽¹⁾		13		6		29		25

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

Other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds for Dominion were not material for the three and nine months ended September 30, 2013 and 2012.

Blue Racer

In December 2012, Dominion formed Blue Racer with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. Blue Racer is an equal partnership between Dominion and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital. In March 2013, DTI sold Line TL-404 to Blue Racer and received approximately $47 million in cash proceeds resulting in an approximately $25 million ($14 million after-tax) gain. Phase 1 of the Natrium natural gas processing and fractionation facility was completed in the second quarter of 2013 and was contributed to Blue Racer in the third quarter of 2013, resulting in an increased equity method investment in Blue Racer of $473 million. Also in the third quarter of 2013, East Ohio sold Line TPL-2A and DTI sold Line TL-388 to Blue Racer and received approximately $83 million in cash proceeds resulting in an approximately $75 million ($42 million after-tax) gain.

PAGE 43

Virginia Power

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, 2013
Marketable equity securities:
U.S.:
Large Cap	$	505	$	433	$	—		$	938
Other		23		10		—			33
Marketable debt securities:
Corporate bonds		191		9		(3	)		197
U.S. Treasury securities and agency debentures		209		2		(2	)		209
State and municipal		157		6		(3	)		160
Cost method investments		103		—		—			103
Cash equivalents and other⁽²⁾		28		—		—			28

Total	$	1,216	$	460	$	(8	)⁽³⁾	$	1,668

December 31, 2012
Marketable equity securities:
U.S.:
Large Cap	$	481	$	298	$	—		$	779
Other		20		7		—			27
Marketable debt securities:
Corporate bonds		179		17		—			196
U.S. Treasury securities and agency debentures		231		4		(1	)		234
State and municipal		106		11		—			117
Other		1		—		—			1
Cost method investments		117		—		—			117
Cash equivalents and other⁽²⁾		44		—		—			44

Total	$	1,179	$	337	$	(1	)⁽³⁾	$	1,515

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

(2)	Includes pending sales of securities of $4 million and $6 million at September 30, 2013 and December 31, 2012, respectively.

(3)	The fair value of securities in an unrealized loss position was $247 million and $104 million at September 30, 2013 and December 31, 2012, respectively.

The fair value of Virginia Power’s marketable debt securities at September 30, 2013 by contractual maturity is as follows:


	Amount
(millions)
Due in one year or less	$	30
Due after one year through five years		158
Due after five years through ten years		199
Due after ten years		179

Total	$	566

PAGE 44

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
(millions)
Proceeds from sales	$	140	$	128	$	464	$	481
Realized gains⁽¹⁾		8		6		34		27
Realized losses⁽¹⁾		5		2		13		9

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

Other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds for Virginia Power were not material for the three and nine months ended September 30, 2013 and 2012.

PAGE 45

Note 11. Regulatory Assets and Liabilities

Regulatory assets and liabilities include the following:


	September 30, 2013		December 31, 2012
(millions)
Dominion
Regulatory assets:
Deferred rate adjustment clause costs⁽¹⁾	$	72	$	55
Derivatives⁽²⁾		18		—
Unrecovered gas cost⁽³⁾		21		59
Plant retirement⁽⁴⁾		6		25
Other		67		64

Regulatory assets-current⁽⁵⁾		184		203

Unrecognized pension and other postretirement benefit costs⁽⁶⁾		934		1,210
Deferred rate adjustment clause costs⁽¹⁾		257		173
Income taxes recoverable through future rates⁽⁷⁾		164		140
Derivatives⁽²⁾		34		105
Other		89		89

Regulatory assets-non-current		1,478		1,717

Total regulatory assets	$	1,662	$	1,920

Regulatory liabilities:
PIPP⁽⁸⁾	$	143	$	100
Other		45		36

Regulatory liabilities-current⁽⁹⁾		188		136

Provision for future cost of removal and AROs⁽¹⁰⁾		1,031		985
Decommissioning trust⁽¹¹⁾		617		501
Other		70		28

Regulatory liabilities-non-current		1,718		1,514

Total regulatory liabilities	$	1,906	$	1,650

Virginia Power
Regulatory assets:
Deferred rate adjustment clause costs⁽¹⁾	$	72	$	51
Derivatives⁽²⁾		18		—
Plant retirement⁽⁴⁾		6		25
Other		50		43

Regulatory assets-current⁽⁵⁾		146		119

Deferred rate adjustment clause costs⁽¹⁾		204		127
Income taxes recoverable through future rates⁽⁷⁾		132		110
Derivatives⁽²⁾		34		105
Other		50		54

Regulatory assets-non-current		420		396

Total regulatory assets	$	566	$	515

Regulatory liabilities:
Other	$	37	$	32

Regulatory liabilities-current⁽⁹⁾		37		32

Provision for future cost of removal⁽¹⁰⁾		799		763
Decommissioning trust⁽¹¹⁾		617		501
Other		55		21

Regulatory liabilities-non-current		1,471		1,285

Total regulatory liabilities	$	1,508	$	1,317

PAGE 46

(1)	Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 12 for more information.

(2)	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.

(3)	Reflects unrecovered gas costs at Dominion’s regulated gas operations, which are recovered through annual filings with the applicable regulatory authority.

(4)	Reflects costs anticipated to be recovered in base rates for certain coal units expected to be retired.

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

(6)	Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain of Dominion’s rate-regulated subsidiaries.

(7)

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.

(8)	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.

(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 AROs.

At September 30, 2013, approximately $102 million of Dominion’s and $65 million of Virginia Power’s regulatory assets represented past expenditures on which they do not currently earn a return. These expenditures are expected to be recovered within the next two years.

Note 12. 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. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any 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 47

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 year each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 1.5% for four of the projects (including the Meadow Brook-to-Loudoun and Carson-to-Suffolk lines, which were completed in 2011) and an incentive of 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008, the incentives were included in the PJM Tariff, and billing for the incentives was made accordingly. In 2012, PJM canceled one of the eleven projects with an estimated cost of $7 million. The total cost for the other ten projects included in Virginia Power’s formula rate for 2013 is $852 million and the remaining projects were completed in 2012. 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 orders 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, did 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.

Other Regulatory Matters

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 13 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2012 and Note 12 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013.

Virginia Regulation

Biennial Review

Pursuant to the Regulation Act, in March 2013, Virginia Power submitted its base rate filings and accompanying schedules in support of the 2013 biennial review of its rates, terms and conditions, as well as of its earnings for test years 2011 and 2012. Virginia Power’s earnings test analysis, as filed, demonstrated it earned an ROE of 10.11% on its generation and distribution services for the combined test period of 2011 and 2012. In September 2013, the Virginia Commission conducted a hearing to receive evidence and public comments regarding Virginia Power’s base rate filings. During the hearing, Virginia Power updated its previous earnings test analysis to demonstrate that it earned an ROE of 10.30% on its generation and distribution services for the applicable test period. Although this ROE is more than 50 basis points below the authorized ROE of 10.9% established in its 2011 biennial review, Virginia Power did not request an increase in base rates for generation or distribution services in this proceeding. No parties to the proceeding asserted that Virginia Power earned above its authorized earnings band for a second consecutive biennial review, meaning that base rates are not statutorily subject to change in this proceeding. The Virginia Commission’s final order must be issued no later than November 28, 2013.

In October 2013, Virginia Power filed a voluntary agreement with the Virginia Commission, proposing to issue a base rate credit of approximately $9 million from its 2012 revenues. This voluntary base rate credit, if approved, would be effective April 1, 2014 and amortized for a twelve-month period. This amount has no effect upon Virginia Power’s past or future earnings test results, and it does not constitute a credit or rate adjustment for purposes of the Regulation Act. This credit is intended to offset and eliminate the revenue requirement increase for customers in certain rate adjustment clause cases resulting from the timing of a Virginia Power securities issuance. A decision on this filing is pending.

DSM Riders C1A and C2A

In August 2013, Virginia Power filed an application with the Virginia Commission to continue Rider C1A and Rider C2A. Virginia Power proposed to continue cost recovery associated with DSM programs that were approved in its 2011 DSM case, as well as its previously approved electric vehicle pilot program. Virginia Power further requested approval to launch three new energy efficiency DSM programs that would be marketed as part of its existing non-residential bundle of DSM offerings. The requested revenue requirements are approximately $1 million for Rider C1A and approximately $35 million for Rider C2A. These amounts include operating expenses for Virginia Power’s proposed and previously approved programs above for

PAGE 48

the rate year beginning May 1, 2014 (including a gross-up or margin on expenses for energy efficiency programs), true-ups of the 2012 calendar year costs for the previously approved programs and carrying costs on the over-/under-recovery of costs. Virginia Power also proposed a combined spending cap of approximately $114 million, inclusive of lost revenues, for its three new DSM programs. This matter is pending.

Virginia Fuel Expenses

In October 2013, Virginia Power filed a voluntary request with the Virginia Commission to reduce its currently-approved fuel factor rate from 2.942 ¢/kWh to 2.572 ¢/kWh effective for usage on and after December 1, 2013, due to an anticipated over-recovery. This request is expected to reduce Virginia Power’s anticipated fuel recoveries through June 30, 2014 by more than $140 million. At September 30, 2013, Virgina Power’s Consolidated Balance Sheet reflected $20 million of other current liabilities and $47 million of noncurrent regulatory liabilities related to fuel recoveries. Virginia Power has requested an order on this request by November 20, 2013.

Bremo Power Station

In September 2013, the Virginia Commission issued its final order approving an amended and reissued CPCN that would allow Virginia Power to convert Bremo Units 3 and 4 from coal to natural gas as their fuel source. The converted units must be in service by July 1, 2014, although this deadline can be extended for good cause. The proposed conversion will preserve 227 MW (net) of existing capacity and is expected to cost approximately $53 million, excluding financing costs.

Brunswick County and Generation Rider BW

In August 2013, three motions for reconsideration were filed with the Virginia Commission, asking that it reconsider its August 2013 final order approving a CPCN for construction of Brunswick County. In August 2013, the Virginia Commission granted the motions for the purpose of continuing its jurisdiction over these matters. Also in August 2013, two notices were filed to appeal the Virginia Commission’s final order to the Supreme Court of Virginia. In September 2013, Virginia Power filed its notices of intent to participate in both appeals as an appellee. These matters are pending.

The Virginia Commission previously approved Rider BW in conjunction with its approval of Brunswick County. In November 2013, Virginia Power requested Virginia Commission approval of its annual update for Rider BW for the twelve-month rate year beginning September 1, 2014, utilizing a 12.5% ROE (inclusive of a 100 basis point statutory enhancement) consistent with the base ROE that Virginia Power has proposed, and which is pending a decision, in its 2013 biennial review case. Virginia Power proposed an approximately $101 million revenue requirement for the rate year. This case is pending.

North Anna

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. In April 2013, Virginia Power decided to replace the reactor design previously selected for a potential unit with ESBWR technology.

If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power filed the first of its two-part amendment to the COL application with the NRC in July 2013 to reflect the ESBWR technology, and expects to file the second part of the amendment by the end of 2013. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

FERC - Gas

Natrium-to-Market Project

In September 2013, DTI received FERC authorization to construct the $42 million Natrium-to-Market project. The project is designed to provide 185,000 dekatherms per day of firm transportation from an interconnect between DTI and the Natrium facility to DTI’s interconnect with Texas Eastern Transmission, LP in Greene County Pennsylvania. Four customers have entered into binding precedent agreements for the full project capacity under 8-year and 13-year terms. The project is anticipated to be in service in November 2014.

FERC - Other

Pipeline G-150

In May 2012, Dominion began construction of the $147 million pipeline G-150 project. The pipeline is designed to transport approximately 27,000 barrels per day of ethane from the Natrium facility to an interconnect with the ATEX line of Enterprise near Follansbee, West Virginia. Dominion NGL Pipelines, LLC, a subsidiary of Dominion, owns the 58-mile pipeline and associated equipment. Transportation services on the pipeline will be subject to FERC regulation pursuant to the Interstate Commerce Act. In August 2013, Dominion filed a petition for declaratory order requesting FERC approval, by mid-November 2013, of (1) general rate structure, (2) rate and terms for committed shipper, and (3) rate design for uncommitted shippers. The facilities are anticipated to be available in the first quarter of 2014 following commencement of operation of Enterprise’s ATEX line and resumption of operations at the Natrium facility. Dominion NGL Pipelines, LLC is expected to be contributed to Blue Racer prior to commencement of service.

PAGE 49

Note 13. Variable Interest Entities

As discussed in Note 15 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2012, 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.

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 $920 million as of September 30, 2013. Virginia Power paid $53 million and $52 million for electric capacity and $29 million and $27 million for electric energy to these entities in the three months ended September 30, 2013 and 2012, respectively. Virginia Power paid $161 million and $160 million for electric capacity and $74 million and $62 million for electric energy to these entities in the nine months ended September 30, 2013 and 2012, respectively.

Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $88 million and $86 million for the three months ended September 30, 2013 and 2012, respectively, and $248 million and $238 million for the nine months ended September 30, 2013 and 2012, 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.

Dominion leased the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. Dominion made annual lease payments of approximately $53 million.

Juniper was formed in 2003 as a limited partnership and was organized for the purpose of acquiring and constructing a number of assets for lease. Such assets were financed with proceeds from the issuance of bank debt, privately placed long-term debt and partnership capital received from Juniper’s general and limited partners. Dominion had no voting equity interest in Juniper. Because Juniper had been subject to the business scope exception, Dominion was not required to evaluate whether Juniper was a VIE prior to October 2011.

Through September 30, 2011, Juniper held various power plant leases, including Fairless. In October 2011, the last lease other than Fairless expired and the related asset was sold by Juniper. With Fairless being its sole remaining asset, Juniper no longer qualified as a business as of October 2011, which required that Dominion determine whether Juniper was a VIE. Dominion concluded Juniper was a VIE because the entity’s capitalization was insufficient to support its operations, the power to direct the most significant activities of the entity was not held by the equity holders, and Dominion guaranteed a portion of the residual value of Fairless. The activities that most significantly impacted Juniper’s economic performance related to the operation of Fairless. The decisions related to the operations of Fairless were made by Dominion and as such, Dominion was considered the primary beneficiary.

Accordingly, Dominion consolidated Juniper in October 2011 and recorded, at fair value, approximately $957 million of property, plant and equipment, $896 million of debt and $61 million of noncontrolling interests. The debt was non-recourse to Dominion and was secured by Juniper’s assets. The annual lease payments made by Dominion to Juniper for Fairless were eliminated in the Consolidated Statements of Income and were excluded from the lease commitments table in Note 22 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2012. Dominion did not provide any financial or other support to Juniper that it was not previously contractually required to provide.

In August 2013, the lease expired and Dominion purchased Fairless for $923 million from Juniper per the terms of the lease agreement. However, as Dominion had previously consolidated Juniper, the purchase was accounted for as an equity transaction to acquire the noncontrolling interests from Juniper for $923 million, while Dominion retained control of Fairless. The acquisition resulted in the removal of securities due within one year-VIE and noncontrolling interests from Dominion’s Consolidated Balance Sheet as of September 30, 2013.

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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, 2013, Dominion’s commercial paper and letters of credit outstanding, as well as its 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	$	2,145	$	—	$	855
Joint revolving credit facility⁽²⁾		500		—		18		482

Total	$	3,500	$	2,145	$	18	$	1,337

(1)	Effective September 2013, the maturity date was extended from September 2017 to September 2018. 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 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. 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.

At September 30, 2013, 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 Sub-limit Capacity Available
(millions)
Joint revolving credit facility⁽¹⁾	$	1,000	$	485	$	—	$	515
Joint revolving credit facility⁽²⁾		250		—		1		249

Total	$	1,250	$	485	$	1	$	764

(1)

Effective September 2013, the maturity date was extended from September 2017 to September 2018. 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 2013, the maturity date was extended from September 2017 to September 2018. As of September 30, 2013, this facility supports approximately $119 million of certain variable rate tax-exempt financings of Virginia Power.

Long-term Debt

In January 2013, Virginia Power issued $250 million of 1.2% senior notes and $500 million of 4.0% senior notes that mature in 2018 and 2043, respectively.

In March 2013, Virginia Power issued $500 million of 2.75% senior notes that mature in 2023.

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In March 2013, Virginia Power redeemed the $50 million 2.5% IDA of the Town of Louisa, Virginia Solid Waste and Sewage Disposal Revenue Bonds, Series 2001A, that would have otherwise matured in March 2031. Virginia Power intends to redeem the $10 million 2.5% and the $30 million 2.5% IDA of the Town of Louisa, Virginia Solid Waste and Sewage Disposal Revenue Bonds, Series 1997A and 2000A, that would otherwise mature in April 2022 and September 2030, respectively. The bonds are expected to be redeemed on or before April 1, 2014 at the amount of principal then outstanding plus accrued interest. At September 30, 2013, the bonds were included in securities due within one year in Virginia Power’s Consolidated Balance Sheets.

In connection with the sale of Kincaid, in May 2013 Kincaid redeemed its 7.33% senior secured bonds due June 2020 with an outstanding principal amount of $145 million. The bonds were redeemed for approximately $185 million, including a make-whole premium and accrued interest.

In connection with the sale of Brayton Point, Brayton Point provided notice of defeasance for three series of MDFA tax-exempt bonds, totaling approximately $257 million in outstanding principal amount, that would have otherwise matured in 2036 through 2042. In June 2013, Brayton Point delivered approximately $284 million to fund an irrevocable trust for the purpose of paying maturing principal and interest due through and including the earliest redemption dates of the bonds in 2016 and 2019. The bonds are no longer included in Dominion’s Consolidated Balance Sheet.

In June 2013, Brayton Point obtained bondholder consent and entered into a supplement to the Loan and Trust Agreement for approximately $75 million of variable rate MDFA Solid Waste Disposal Revenue Bonds, Series 2010B due 2041. The supplement and associated assignment agreement changed the sole obligor under the bonds from Brayton Point to Dominion; the bonds continue to be included in Dominion’s Consolidated Balance Sheet.

In August 2013, Virginia Power issued $585 million of 4.65% senior notes that mature in 2043.

Convertible Securities

At September 30, 2013, Dominion had $44 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, 2013, the conversion rate had been adjusted, primarily due to individual dividend payments above the level paid at issuance, to 29.7664 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $33.59. If the outstanding notes as of September 30, 2013 were all converted, it would result in the issuance of approximately 600,000 additional shares of common stock.

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, 2013, the senior notes were eligible for conversion and approximately $38 million of the notes were converted by holders. The senior notes are eligible for conversion during the fourth quarter of 2013.

Junior Subordinated Notes Payable to Affiliated Trusts

In January 2013, Dominion repaid its $258 million 7.83% unsecured junior subordinated debentures and redeemed all 250 thousand units of the $250 million 7.83% Dominion Resources Capital Trust I capital securities due December 1, 2027. The securities were redeemed at a price of $1,019.58 per capital security plus accrued and unpaid distributions.

Remarketable Subordinated Notes

In June 2013, Dominion issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B 6% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the New York Stock Exchange under the symbols DCUA and DCUB, respectively.

Each Corporate Unit consists of a stock purchase contract and 1/20 interest in a RSN issued by Dominion. The stock purchase contracts obligate the holders to purchase shares of Dominion common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is $50 and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion common stock near the settlement date. The RSNs are pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.

Dominion makes quarterly interest payments on the RSNs and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. Dominion may defer payments on the stock purchase contracts and the RSNs for one or

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more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, Dominion may not make any cash distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the RSNs.

Dominion has recorded the present value of the stock purchase contract payments as a liability offset by a charge to additional paid-in capital in equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, Dominion applies the treasury stock method to the Equity Units. These securities did not have an effect on diluted EPS for the third quarter of 2013.

Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion will issue between 8.4 million and 9.9 million shares of its common stock in both April 2016 and July 2016. A total of 22.5 million shares of Dominion’s common stock has been reserved for issuance in connection with the stock purchase contracts.

Selected information about Dominion’s Equity Units is presented below:


Issuance Date	Units Issued		Total Net Proceeds		Total Long- term Debt		RSN Annual Interest Rate			Stock Purchase Contract Annual Rate			Stock Purchase Contract Liability		Stock Purchase Settlement Date		RSN Maturity Date
(millions, except interest rates)
6/7/2013		11	$	533.5	$	550.0		1.070	%		5.055	%	$	76.7		4/1/2016		4/1/2021
6/7/2013		11	$	533.5	$	550.0		1.180	%		4.820	%	$	79.3		7/1/2016		7/1/2019

Regulated Natural Gas Financing Plans

In September 2013, Dominion announced the formation of DGH, a first tier subsidiary holding company for the majority of Dominion’s regulated natural gas businesses. Specifically, Dominion transferred direct ownership of East Ohio, DTI and Dominion Iroquois, Inc., the latter of which holds a 24.72% general partnership interest in Iroquois Gas Transmission System, L.P., to DGH on September 30, 2013. Dominion intends to seek approval from the West Virginia Commission in 2014 for the transfer of direct ownership of Hope Gas, Inc. to DGH. DGH issued $1.2 billion principal amount of unsecured senior notes in a private placement on October 22, 2013 and will be the primary financing entity for Dominion’s regulated natural gas businesses. DGH expects to become an SEC registrant in 2014. DGH used the proceeds from the October 2013 offering to settle intercompany long-term notes from Dominion and to repay a portion of its intercompany revolving credit agreement balances with Dominion.

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 such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or 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. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any 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

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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.

The EPA established CAIR with the intent to require significant reductions in SO₂ and NO_Xemissions 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 SO₂ and NO_xemissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO₂ 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 SO₂ 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 were 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, which was denied in January 2013. The mandate vacating CSAPR was issued in February 2013. In March 2013, the EPA and several environmental groups filed petitions with the U.S. Supreme Court requesting review of the decision to vacate and remand CSAPR. In June 2013, the U.S. Supreme Court granted the EPA’s petition seeking review of the D.C. Circuit’s decision that vacated and remanded CSAPR. 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 concerned 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. In May 2010, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerned historical operating changes and capital improvements undertaken at Brayton Point.

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. Dominion entered into settlement discussions with the U.S. government and reached an agreement to settle the allegations. In April 2013, the U.S. government lodged a consent decree and complaint with the U.S. District Court for the Central District of Illinois that resolves all alleged violations at State Line, Kincaid and Brayton Point. The settlement mandates the closure of State Line, installation of certain control technology at Kincaid and Brayton Point, the achievement of certain emissions limitations, payment of a civil penalty of $3 million and funding of $10 million in environmental mitigation projects. The consent decree underwent a 30-day public comment period and the U.S. government has filed a motion with the court requesting that the decree be entered as lodged. In July 2013, the court entered the consent decree, concluding the enforcement action. Dominion previously accrued a liability of $13 million related to this matter. State Line ceased operations in March 2012 and was sold in June 2012. The installation of pollution control technology was in progress at Kincaid and had been completed at Brayton Point. In August 2013, Dominion sold Kincaid and Brayton Point. Under the terms of the sale transaction, Dominion retained the $13 million liability associated with the settlement agreement. Dominion has paid the civil penalty and is implementing the environmental mitigation projects.

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 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

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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 jointly, severally and strictly 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.

Dominion has determined that it is associated with 17 former manufactured gas plant sites, three of which pertain to Virginia Power. 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 former sites with which Dominion and Virginia Power are 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, Connecticut, and Maryland, among other states, have joined RGGI, a multi-state effort to reduce CO₂ emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO₂ 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 CO₂ emissions. During 2012, RGGI underwent a program review, and in February 2013, revisions to the RGGI model rule were issued that include a reduction of the regional CO₂ emissions cap from 165 million tons to 91 million tons beginning in January 2014, with an additional 2.5% reduction per year through 2020. The revisions also include changes to compliance demonstration requirements for regulated entities, offset and cost containment mechanisms. The RGGI states are in the process of conducting the regulatory and/or legislative processes required to amend existing state regulations to implement the RGGI program changes. Dominion is in the process of evaluating these revisions as to potential impacts on Dominion’s operations in RGGI states. However, as a result of the recent sales of several power plants located in these states, Dominion does not expect that RGGI will have a material effect on operations, financial condition, and/or cash flows.

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Natrium and Blue Racer

In January 2011, Dominion announced the development of a natural gas processing and fractionation facility in Natrium, West Virginia, and in July 2011 it executed a contract for the construction of the first phase of the facility. The first phase of the project is fully contracted and was placed into service in May 2013. In August 2013, the Natrium natural gas processing and fractionation facility was contributed to the Blue Racer joint venture. In September 2013, the Natrium facility was shut down following a fire at the plant. This matter is not anticipated to have a material impact on Dominion’s financial condition, results of operations, and/or cash flows.

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.

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. Implementation of these enhancements is currently in progress. 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.

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Nuclear Operations

Nuclear Insurance

The Price-Anderson Amendments Act of 1988 provides the public up to $13.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

Effective June 7, 2013 for Kewaunee and July 1, 2013 for Millstone and Virginia Power’s nuclear units, the levels of nuclear property insurance coverage were reduced to the following:


	Coverage
(billions)
Dominion
Millstone	$	1.70
Kewaunee		1.06
Virginia Power⁽¹⁾
Surry	$	1.70
North Anna		1.70

(1)	Surry and North Anna share a blanket property limit of $450 million.

The Companies’ nuclear property insurance coverage for Millstone, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. Kewaunee meets the NRC minimum requirement of $1.06 billion. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $71 million and $39 million, respectively. Based on the severity of the incident, the board of directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

Millstone and Virginia Power also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, the Companies are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $19 million and $9 million, respectively. Kewaunee’s accidental outage policy for replacement power costs was canceled on February 1, 2013.

ODEC, a part owner of North Anna, and Massachusetts Municipal Wholesale Electric Company and Green Mountain Power Corporation, part owners of Millstone’s Unit 3, are responsible to Dominion and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

Guarantees

Dominion

At September 30, 2013, Dominion had issued $68 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of September 30, 2013, Dominion’s exposure under these guarantees was $38 million, primarily related to certain reserve requirements associated with non-recourse financing.

In addition to the above guarantees, Dominion and its partners, Shell and BP, may be required to make additional periodic equity contributions to NedPower and Fowler Ridge in connection with certain funding requirements associated with their respective non-recourse financings. As of September 30, 2013, Dominion’s maximum remaining cumulative exposure under these equity funding agreements was $90 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million.

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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 the 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, 2013, Dominion had issued the following subsidiary guarantees:


	Stated Limit		Value⁽¹⁾
(millions)
Subsidiary debt⁽²⁾	$	27	$	27
Commodity transactions⁽³⁾		3,181		343
Nuclear obligations⁽⁴⁾		232		55
Cove Point⁽⁵⁾		335		—
Other⁽⁶⁾		648		92

Total	$	4,423	$	517

(1)

Represents the estimated portion of the guarantee’s stated limit that is utilized as of September 30, 2013 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)	Guarantee of debt of a DEI subsidiary. In the event of default by the subsidiary, 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. The agreement for Kewaunee also provides for funds through the completion of decommissioning.

(5)	Guarantees related to Cove Point, including agreements to support terminal service and transportation agreements as well as an engineering, procurement and construction contract for new liquefaction facilities. Includes certain guarantees that do not have stated limits.

(6)

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, 2013, Dominion had purchased $146 million of surety bonds, including $59 million at Virginia Power, and authorized the issuance of letters of credit by financial institutions of $18 million, including $1 million at Virginia Power, to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

Note 16. Credit Risk

Dominion’s and Virginia Power’s accounting policies for credit risk are discussed in Note 23 to the Consolidated Financial Statements in their Annual Report on Form 10-K for the year ended December 31, 2012.

At September 30, 2013, Dominion’s credit exposure totaled $205 million. Of this amount, investment grade counterparties, including those internally rated, represented 63%. No counterparty exposure exceeded 10% of Dominion’s total exposure.

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, 2013 and December 31, 2012, Dominion would have been required to post an additional $48 million and $110 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted

PAGE 58

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 approximately $3 million and $4 million in collateral at September 30, 2013 and December 31, 2012, respectively, 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, 2013 and December 31, 2012 was $86 million and $163 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, 2013 and December 31, 2012. See Note 9 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. As of September 30, 2013 and December 31, 2012, Virginia Power’s derivative liabilities with affiliates were not material.

DRS and other 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,
	2013		2012		2013		2012
(millions)
Commodity purchases from affiliates	$	138	$	129	$	328	$	285
Services provided by affiliates		109		107		311		298

Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were $243 million in short-term demand note borrowings from Dominion as of December 31, 2012. There were no short-term demand note borrowings from Dominion as of September 30, 2013. Virginia Power’s outstanding borrowings, net of repayments, under the Dominion money pool for its nonregulated subsidiaries totaled $192 million as of December 31, 2012. There were no borrowings as of September 30, 2013. Interest charges related to Virginia Power’s borrowings from Dominion were not material for the three and nine months ended September 30, 2013 and 2012.

PAGE 59

Note 18. Employee Benefit Plans

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


	Pension Benefits						Other Postretirement Benefits
	2013			2012			2013			2012
(millions)
Three Months Ended September 30,
Service cost	$	31		$	29		$	10		$	11
Interest cost		69			67			19			20
Expected return on plan assets		(116	)		(108	)		(24	)		(19	)
Amortization of prior service credit		—			—			(3	)		(4	)
Amortization of net loss		37			33			2			2
Settlements and curtailments⁽¹⁾		—			—			—			(4	)

Net periodic benefit cost	$	21		$	21		$	4		$	6

Nine Months Ended September 30,
Service cost	$	100		$	87		$	34		$	33
Interest cost		202			201			56			60
Expected return on plan assets		(345	)		(323	)		(68	)		(60	)
Amortization of prior service cost (credit)		2			2			(9	)		(10	)
Amortization of net loss		127			99			6			5
Settlements and curtailments⁽¹⁾⁽²⁾		(2	)		—			(15	)		(4	)

Net periodic benefit cost	$	84		$	66		$	4		$	24

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

(2)	2013 amount relates primarily to the decommissioning of Kewaunee.

Pension and Other Postretirement Plan Remeasurement

Dominion remeasured all of its pension and other postretirement benefit plans in the second quarter of 2013. The remeasurement resulted in a reduction in the pension benefit obligation of approximately $354 million and a reduction in the accumulated postretirement benefit obligation of approximately $78 million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The remeasurement is expected to reduce net periodic benefit cost for 2013 by approximately $36 million, excluding the impacts of curtailments. The discount rate used for the remeasurement was 4.8% for the pension plans and 4.7% for the other postretirement benefit plans. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.

Employer Contributions

During the nine months ended September 30, 2013, Dominion made no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion expects to contribute approximately $12 million to its other postretirement benefit plans through Voluntary Employees’ Beneficiary Associations during the remainder of 2013.

Note 19. Goodwill

The changes in Dominion’s carrying amount and segment allocation of goodwill are presented below:


	Dominion Generation			Dominion Energy			DVP			Corporate and Other		Total
(millions)
Balance at December 31, 2011⁽¹⁾	$	1,338		$	712		$	1,091		$	—	$	3,141
Asset disposition adjustment		—			(11	)		—			—		(11	)

Balance at December 31, 2012⁽¹⁾	$	1,338		$	701		$	1,091		$	—	$	3,130
Asset disposition adjustment		(16	)⁽²⁾		(24	)⁽³⁾		(3	)⁽²⁾		—		(43	)

Balance at September 30, 2013⁽¹⁾	$	1,322		$	677		$	1,088		$	—	$	3,087

(1)	Goodwill amounts do not contain any accumulated impairment losses.

(2)	See Note 3 in this report for a discussion of Dominion’s dispositions and related goodwill write-offs.

(3)	Related to assets sold or contributed to Blue Racer.

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Note 20. 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 the net impact of operations that are expected to be or are currently discontinued. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

In the second quarter of 2013, Dominion commenced a restructuring of its producer services business, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates. The restructuring will result in the termination of natural gas trading and certain energy marketing activities. As a result, the earnings impact from natural gas trading and certain energy marketing activities has been included in the Corporate and Other Segment of Dominion.

In the nine months ended September 30, 2013, Dominion reported after-tax net expense of $148 million for specific items in the Corporate and Other segment, with $144 million of these net expenses attributable to its operating segments. In the nine months ended September 30, 2012, Dominion reported after-tax net expense of $413 million for specific items in the Corporate and Other segment, with $422 million of these net expenses attributable to its operating segments.

The net expense for specific items in 2013 primarily related to the impact of the following items:

•

A $135 million ($92 million after-tax) net loss from discontinued operations of Brayton Point and Kincaid, including debt extinguishment of $64 million ($38 million after-tax) related to the sale, impairment charges of $48 million ($28 million after-tax), a $17 million ($18 million after-tax) loss on the sale which includes a $16 million write-off of goodwill, and a $6 million ($8 million after-tax) loss from operations, attributable to Dominion Generation;

•

A $130 million ($74 million after-tax) net loss, including a $55 million ($33 million after-tax) impairment charge related to certain natural gas infrastructure assets and a $75 million ($41 million after-tax) loss related to the producer services business discussed above, attributable to Dominion Energy; and

•

A $28 million ($17 million after-tax) charge primarily reflecting severance pay and other benefits related to workforce reductions, attributable to all segments; partially offset by

•

A $66 million ($40 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation; and

•

A $35 million ($25 million after-tax) gain related to the sale of Dominion’s equity method investment in Elwood, attributable to Dominion Generation.

The net expense 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 $98 million ($72 million after-tax) net loss from discontinued operations of Brayton Point and Kincaid, 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 two merchant power stations in the third quarter of 2012;

•

A $69 million ($42 million after-tax) charge reflecting restoration costs associated with damage caused by late June 2012 summer storms, attributable to DVP; 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.

PAGE 61

The Corporate and Other Segment of Virginia Power primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

In the nine months ended September 30, 2013 and 2012, Virginia Power reported after-tax net expense of $5 million and $41 million, respectively, for specific items in the Corporate and Other segment, all of which was attributable to its operating segments.

The net expense 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 2012 summer storms, attributable to DVP.

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


	DVP		Dominion Generation⁽¹⁾		Dominion Energy		Corporate and Other⁽¹⁾			Adjustments/ Eliminations			Consolidated Total
(millions)
Three Months Ended September 30,
2013
Total revenue from external customers	$	829	$	1,882	$	361	$	(10	)	$	370		$	3,432
Intersegment revenue		8		110		281		158			(557	)		—

Total operating revenue		837		1,992		642		148			(187	)		3,432
Loss from discontinued operations		—		—		—		(23	)		—			(23	)
Net income (loss) attributable to Dominion		124		338		169		(62	)		—			569


2012
Total revenue from external customers	$	836	$	1,824	$	291	$	37		$	344		$	3,332
Intersegment revenue		6		110		281		164			(561	)		—

Total operating revenue		842		1,934		572		201			(217	)		3,332
Loss from discontinued operations		—		—		—		(52	)		—			(52	)
Net income (loss) attributable to Dominion		119		363		104		(377	)		—			209


Nine Months Ended September 30,
2013
Total revenue from external customers	$	2,508	$	5,034	$	1,326	$	54		$	1,013		$	9,935
Intersegment revenue		56		237		821		464			(1,578	)		—

Total operating revenue		2,564		5,271		2,147		518			(565	)		9,935
Loss from discontinued operations		—		—		—		(92	)		—			(92	)
Net income (loss) attributable to Dominion		398		730		472		(334	)		—			1,266


2012
Total revenue from external customers	$	2,573	$	4,960	$	1,278	$	109		$	814		$	9,734
Intersegment revenue		81		275		701		459			(1,516	)		—

Total operating revenue		2,654		5,235		1,979		568			(702	)		9,734
Loss from discontinued operations		—		—		—		(94	)		—			(94	)
Net income (loss) attributable to Dominion		428		762		362		(591	)		—			961

(1)	2012 amounts have been recast to reflect Brayton Point and Kincaid 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.

PAGE 62

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,
2013
Operating revenue	$	470	$	1,589	$	—		$	2,059
Net income		123		262		2			387


2012
Operating revenue	$	505	$	1,581	$	—		$	2,086
Net income		128		283		4			415


Nine Months Ended September 30,
2013
Operating revenue	$	1,366	$	4,184	$	—		$	5,550
Net income (loss)		355		587		(3	)		939


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

PAGE 63

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

•

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, earthquakes and changes in water temperatures and availability that can cause outages and property damage to facilities;

•

Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;

•

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 at facilities in which Dominion has an ownership interest;

•

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;

•

Volatility in the value of investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion;

•

Fluctuations in interest rates;

•

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 acquisitions, divestitures and retirements of assets based on asset portfolio reviews;

•

Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;

•

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;

•

Political and economic conditions, including inflation and deflation;

PAGE 64

•

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

•

Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in customer growth or usage patterns, including as a result of energy conservation programs and changes in demand for Dominion’s natural gas services;

•

Additional competition in industries in which Dominion operates, including in electric markets in which Dominion’s merchant generation facilities operate, and competition in the construction and ownership of electric transmission facilities in Virginia Power’s service territory, in connection with FERC Order 1000;

•

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;

•

Changes in operating, maintenance and construction costs;

•

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

•

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

•

Adverse outcomes in litigation matters or regulatory proceedings; and

•

The impact of operational hazards and other catastrophic events.

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, 2012 and in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013.

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, 2013, 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, 2012. 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.

Dominion

Results of Operations

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


	2013		2012		$ Change
(millions, except EPS)
Third Quarter
Net income attributable to Dominion	$	569	$	209	$	360
Diluted EPS		0.98		0.36		0.62
Year-To-Date
Net income attributable to Dominion	$	1,266	$	961	$	305
Diluted EPS		2.19		1.68		0.51

Overview

Third Quarter 2013 vs. 2012

Net income attributable to Dominion increased by $360 million primarily due to the absence of charges recorded in 2012 following management’s decision to cease operations and begin decommissioning Kewaunee in 2013 and gains from the sale of assets to Blue Racer.

Year-To-Date 2013 vs. 2012

Net income attributable to Dominion increased by 32% primarily due to the absence of charges recorded in 2012 following management’s decision to cease operations and begin decommissioning Kewaunee in 2013, an increase in regulated natural gas transmission operations, and gains from the sale of assets to Blue Racer. Unfavorable drivers include lower margins from retail energy marketing activities and merchant generation operations.

PAGE 65

Analysis of Consolidated Operations

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


	Third Quarter									Year-To-Date
	2013			2012			$ Change			2013			2012			$ Change
(millions)
Operating revenue	$	3,432		$	3,332		$	100		$	9,935		$	9,734		$	201
Electric fuel and other energy-related purchases		1,107			1,009			98			2,933			2,816			117
Purchased electric capacity		91			86			5			267			297			(30	)
Purchased gas		232			191			41			996			818			178

Net revenue		2,002			2,046			(44	)		5,739			5,803			(64	)

Other operations and maintenance		525			1,086			(561	)		1,876			2,446			(570	)
Depreciation, depletion and amortization		309			290			19			909			838			71
Other taxes		134			119			15			442			422			20
Other income		86			56			30			222			174			48
Interest and related charges		217			197			20			648			618			30
Income tax expense		305			143			162			709			578			131
Loss from discontinued operations		(23	)		(52	)		29			(92	)		(94	)		2

An analysis of Dominion’s results of operations follows:

Third Quarter 2013 vs. 2012

Net revenue decreased 2%, primarily reflecting:

•

A $49 million decrease from electric utility operations primarily reflecting a decrease in sales to retail customers largely due to a decrease in cooling degree days ($35 million);

•

A $29 million decrease from merchant generation operations primarily reflecting lower generation output due to the May 2013 closure of Kewaunee; and

•

A $17 million decrease in producer services primarily related to unfavorable price changes on economic hedging positions, partially offset by higher physical margins, all associated with natural gas aggregation, marketing and trading activities.

These decreases were partially offset by:

•

A $41 million increase from regulated natural gas transmission operations primarily related to the Appalachian Gateway Project that was placed into service in September 2012 ($12 million), an increase in gathering and storage services ($10 million) and the Northeast Expansion Project that was placed into service in November 2012 ($5 million); and

•

A $12 million increase in retail energy marketing activities primarily due to price risk management activities.

Other operations and maintenance decreased 52%, primarily reflecting:

•

A $468 million decrease related to Kewaunee primarily due to the absence of charges recorded in 2012 following management’s decision to cease operations and begin decommissioning in 2013;

•

Gains from the sale of Line TPL-2A and Line TL-388 to Blue Racer ($75 million); and

•

A $46 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates; partially offset by

•

A $20 million increase in planned outage costs primarily due to an increase in scheduled outage days at certain nuclear utility generation facilities.

Other income increased 54%, primarily due to a gain on the sale of Dominion’s equity method investment in Elwood.

Interest and related charges increased 10%, primarily due to the absence of favorable mark to market recorded in 2012 on freestanding interest rate derivatives.

Income tax expense increased $162 million, primarily reflecting higher pre-tax income in 2013.

Loss from discontinued operations primarily reflects the sale of Brayton Point and Kincaid, which were reclassified to discontinued operations in the first quarter of 2013.

PAGE 66

Year-To-Date 2013 vs. 2012

Net revenue decreased 1%, primarily reflecting:

•

A $107 million decrease in retail energy marketing activities primarily due to the impact of lower margins on electric sales ($69 million) due to higher purchased power costs and price risk management activities ($33 million);

•

An $88 million decrease from merchant generation operations primarily due to lower generation output ($130 million) largely due to a spring 2013 refueling outage at Millstone and the May 2013 closure of Kewaunee, partially offset by higher realized prices ($42 million); and

•

A $68 million decrease in producer services primarily related to unfavorable price changes on economic hedging positions, partially offset by higher physical margins, all associated with natural gas aggregation, marketing and trading activities.

These decreases were partially offset by:

•

A $108 million increase from regulated natural gas transmission operations primarily related to the Appalachian Gateway Project that was placed into service in September 2012 ($51 million), an increase in gathering and storage services ($23 million), NGL activities primarily related to an increase in extraction and fractionation volumes ($16 million) and the Northeast Expansion Project that was placed into service in November 2012 ($15 million);

•

An $84 million increase from electric utility operations primarily reflecting:

•

An increase in rate adjustment clause revenue ($64 million); and

•

The impact ($48 million) of an increase in sales to retail customers primarily due to an increase in heating degree days ($61 million), partially offset by a decrease in sales due to the effect of unfavorable economic conditions on customer usage and other factors ($13 million); partially offset by

•

A decrease in ancillary revenues received from PJM ($9 million) primarily due to a decrease in net operating reserve credits; and

•

A $16 million increase from regulated natural gas distribution operations primarily related to increased volumes related to weather ($10 million) and rate increases related to AMR and PIR programs ($6 million).

Other operations and maintenance decreased 23%, primarily reflecting:

•

A $495 million decrease related to Kewaunee primarily due to the absence of charges recorded in 2012 following management’s decision to cease operations and begin decommissioning in 2013;

•

A $105 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates;

•

Gains from the sale of assets to Blue Racer ($100 million); and

•

A $41 million decrease in storm damage and service restoration costs primarily due to the absence of damage caused by late June summer storms in 2012.

These decreases were partially offset by:

•

A $65 million charge primarily related to impairment charges for certain natural gas infrastructure assets; and

•

A $39 million increase in planned outage costs primarily due to an increase in scheduled outage days at certain merchant generation facilities.

Other income increased 28%, primarily due to higher realized gains (including investment income) on nuclear decommissioning trust funds ($37 million) and a gain on the sale of Dominion’s equity method investment in Elwood ($35 million), partially offset by a decrease in earnings from equity method investments ($12 million).

Income tax expense increased 23%, primarily reflecting higher pre-tax income in 2013.

PAGE 67

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	2013			2012			$ Change			2013			2012			$ Change
(millions, except EPS)
DVP	$	124		$	119		$	5		$	0.21		$	0.21		$	—
Dominion Generation		338			363			(25	)		0.58			0.63			(0.05	)
Dominion Energy		169			104			65			0.29			0.18			0.11

Primary operating segments		631			586			45			1.08			1.02			0.06
Corporate and Other		(62	)		(377	)		315			(0.10	)		(0.66	)		0.56

Consolidated	$	569		$	209		$	360		$	0.98		$	0.36		$	0.62


Year-To-Date
DVP	$	398		$	428		$	(30	)	$	0.69		$	0.75		$	(0.06	)
Dominion Generation		730			762			(32	)		1.26			1.33			(0.07	)
Dominion Energy		472			362			110			0.81			0.63			0.18

Primary operating segments		1,600			1,552			48			2.76			2.71			0.05
Corporate and Other		(334	)		(591	)		257			(0.57	)		(1.03	)		0.46

Consolidated	$	1,266		$	961		$	305		$	2.19		$	1.68		$	0.51

DVP

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


	Third Quarter							Year-To-Date
	2013		2012		% Change			2013		2012		% Change
Electricity delivered (million MWh)		22.1		23.0		(4	)%		62.4		61.7		1	%
Degree days (electric distribution service area):

Cooling		1,029		1,198		(14	)		1,568		1,734		(10	)
Heating		8		5		60			2,372		1,707		39
Average electric distribution customer accounts (thousands)⁽¹⁾		2,477		2,457		1			2,473		2,452		1
Average retail energy marketing customer accounts (thousands)⁽¹⁾		2,090		2,132		(2	)		2,110		2,127		(1	)

(1)	Period average.

PAGE 68

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


	Third Quarter 2013 vs. 2012 Increase (Decrease)						Year-To-Date 2013 vs. 2012 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(6	)	$	(0.01	)	$	13		$	0.02
Other		3			—			(1	)		—
FERC transmission equity return		10			0.02			24			0.04
Retail energy marketing operations⁽¹⁾		8			0.01			(51	)		(0.09	)
Storm damage and service restoration⁽²⁾		1			—			(17	)		(0.03	)
Other operations and maintenance expenses		1			—			7			0.01
Depreciation		(2	)		—			(6	)		(0.01	)
Other		(10	)		(0.02	)		1			—

Change in net income contribution	$	5		$	—		$	(30	)	$	(0.06	)

(1)	Year-To-Date amount includes the impact of the sale of Illinois Gas Contracts in June 2013.

(2)	Year-To-Date amount excludes restoration costs associated with damage caused by late June 2012 summer storms 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
	2013		2012		% Change			2013		2012		% Change
Electricity supplied (million MWh):
Utility		22.3		23.1		(3	)%		62.8		61.8		2	%
Merchant⁽¹⁾		6.9		7.2		(4	)		19.8		21.7		(9	)
Degree days (electric utility service area):
Cooling		1,029		1,198		(14	)		1,568		1,734		(10	)
Heating		8		5		60			2,372		1,707		39

(1)

Excludes 1.6 million and 7.6 million MWh for the three and nine months ended September 30, 2013, respectively, related to Kewaunee, Brayton Point, Kincaid and Dominion’s equity method investment in Elwood. Excludes 3.9 million and 9.6 million MWh for the three and nine months ended September 30, 2012, respectively, related to Kewaunee, State Line, Salem Harbor, Brayton Point, Kincaid, and Dominion’s equity method investment in Elwood.

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


	Third Quarter 2013 vs. 2012 Increase (Decrease)						Year-To-Date 2013 vs. 2012 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Merchant generation margin	$	4		$	0.01		$	(34	)	$	(0.06	)
Regulated electric sales:
Weather		(15	)		(0.02	)		24			0.04
Other		3			—			(3	)		(0.01	)
Rate adjustment clause equity return		2			—			32			0.06
PJM ancillary services		(9	)		(0.02	)		(21	)		(0.04	)
Outage costs		(10	)		(0.02	)		(23	)		(0.04	)
Other		—			—			(7	)		(0.01	)
Share dilution		—			—			—			(0.01	)

Change in net income contribution	$	(25	)	$	(0.05	)	$	(32	)	$	(0.07	)

PAGE 69

Dominion Energy

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


	Third Quarter							Year-To-Date
	2013		2012		% Change			2013		2012		% Change
Gas distribution throughput (bcf):
Sales		2		2		—	%		20		17		18	%
Transportation		40		40		—			202		185		9
Heating degree days (gas distribution service area)		109		142		(23	)		3,773		3,030		25

Average gas distribution customer accounts (thousands)⁽¹⁾:
Sales		241		245		(2	)		244		249		(2	)
Transportation		1,041		1,037		—			1,051		1,046		—

(1)	Period average.

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


	Third Quarter 2013 vs. 2012 Increase (Decrease)					Year-To-Date 2013 vs. 2012 Increase (Decrease)
	Amount			EPS		Amount			EPS
(millions, except EPS)
Weather	$	—		$	—	$	7		$	0.01
Producer services margin⁽¹⁾		(1	)		—		(20	)		(0.04	)
Gas transmission margin		28			0.04		80			0.14
Gains from sale of assets to Blue Racer		42			0.07		56			0.09
Depreciation		(3	)		—		(11	)		(0.02	)
Other		(1	)		—		(2	)		—

Change in net income contribution	$	65		$	0.11	$	110		$	0.18

(1)	Excludes the earnings impact from natural gas trading and certain energy marketing activities reflected in the Corporate and Other segment as of second quarter 2013.

Corporate and Other

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


	Third Quarter									Year-To-Date
	2013			2012			$ Change			2013			2012			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	(13	)	$	(326	)	$	313		$	(144	)	$	(422	)	$	278
Specific items attributable to corporate operations		(1	)		9			(10	)		(4	)		9			(13	)

Total specific items		(14	)		(317	)		303			(148	)		(413	)		265
Other corporate operations		(48	)		(60	)		12			(186	)		(178	)		(8	)

Total net expense	$	(62	)	$	(377	)	$	315		$	(334	)	$	(591	)	$	257
EPS impact	$	(0.10	)	$	(0.66	)	$	0.56		$	(0.57	)	$	(1.03	)	$	0.46

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 20 to the Consolidated Financial Statements in this report for discussion of these items.

PAGE 70

Virginia Power

Results of Operations

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


	Third Quarter							Year-To-Date
	2013		2012		$ Change			2013		2012		$ Change
(millions)
Net income	$	387	$	415	$	(28	)	$	939	$	830	$	109

Overview

Third Quarter 2013 vs. 2012

Net income decreased by 7% primarily due to the impact of less favorable weather on utility operations.

Year-To-Date 2013 vs. 2012

Net income increased by 13% primarily due to an increase in rate adjustment clause revenue, the impact of more favorable weather on utility operations, and the absence of restoration costs associated with damage caused by late June 2012 summer storms.

Analysis of Consolidated Operations

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


	Third Quarter							Year-To-Date
	2013		2012		$ Change			2013		2012		$ Change
(millions)
Operating revenue	$	2,059	$	2,086	$	(27	)	$	5,550	$	5,596	$	(46	)

Electric fuel and other energy-related purchases		651		634		17			1,749		1,850		(101	)
Purchased electric capacity		91		86		5			267		296		(29	)

Net revenue		1,317		1,366		(49	)		3,534		3,450		84

Other operations and maintenance		356		369		(13	)		1,030		1,117		(87	)
Depreciation and amortization		218		203		15			636		579		57
Other taxes		64		48		16			196		179		17
Other income		19		25		(6	)		71		65		6
Interest and related charges		93		97		(4	)		270		297		(27	)
Income tax expense		218		259		(41	)		534		513		21

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

Third Quarter 2013 vs. 2012

Net revenue decreased 4%, primarily reflecting a decrease in sales to retail customers largely due to a decrease in cooling degree days ($35 million).

Other operations and maintenance decreased 4%, primarily reflecting:

•

A $46 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates; partially offset by

•

A $20 million increase in planned outage costs primarily due to an increase in scheduled outage days at certain nuclear generation facilities;

•

A $7 million increase in PJM operating reserves and reactive service charges; and

•

A $7 million increase in contractor services.

Other taxes increased 33%, primarily reflecting the absence of a benefit recognized in 2012 for excess use taxes previously paid.

Income tax expense decreased 16%, primarily reflecting lower pre-tax income in 2013 and changes in the amount of income apportioned among states.

PAGE 71

Year-To-Date 2013 vs. 2012

Net revenue increased 2%, primarily reflecting:

•

An increase in rate adjustment clause revenue ($64 million); and

•

A decrease in ancillary revenues received from PJM ($9 million) primarily due to a decrease in net operating reserve credits.

Other operations and maintenance decreased 8%, primarily reflecting:

•

A $105 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates; and

•

A $41 million decrease in storm damage and service restoration costs primarily due to the absence of damage caused by late June summer storms in 2012; partially offset by

•

A $30 million increase in salaries, wages and benefits; and

•

A $20 million increase in PJM operating reserves and reactive service charges.

Depreciation and amortization increased 10%, 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
	2013		2012		$ Change			2013			2012			$ Change
(millions)
DVP	$	123	$	128	$	(5	)	$	355		$	335		$	20
Dominion Generation		262		283		(21	)		587			534			53

Primary operating segments		385		411		(26	)		942			869			73
Corporate and Other		2		4		(2	)		(3	)		(39	)		36

Consolidated	$	387	$	415	$	(28	)	$	939		$	830		$	109

DVP

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


	Third Quarter							Year-To-Date
	2013		2012		% Change			2013		2012		% Change
Electricity delivered (million MWh)		22.1		23.0		(4	)%		62.4		61.7		1	%
Degree days (electric distribution service area):
Cooling		1,029		1,198		(14	)		1,568		1,734		(10	)
Heating		8		5		60			2,372		1,707		39
Average electric distribution customer accounts (thousands)⁽¹⁾		2,477		2,457		1			2,473		2,452		1

(1)	Period average.

PAGE 72

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


	Third Quarter 2013 vs. 2012 Increase (Decrease)			Year-To-Date 2013 vs. 2012 Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	(6	)	$	13
Other		3			(1	)
FERC transmission equity return		10			24
Storm damage and service restoration⁽¹⁾		1			(17	)
Other operations and maintenance expenses		1			7
Depreciation		(2	)		(6	)
Other		(12	)		—

Change in net income contribution	$	(5	)	$	20

(1)	Year-To-Date amount excludes restoration costs associated with damage caused by late June 2012 summer storms 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
	2013		2012		% Change			2013		2012		% Change
Electricity supplied (million MWh):		22.3		23.1		(3	)%		62.8		61.8		2	%
Degree days (electric utility service area):
Cooling		1,029		1,198		(14	)		1,568		1,734		(10	)
Heating		8		5		60			2,372		1,707		39

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


	Third Quarter 2013 vs. 2012 Increase (Decrease)			Year-To-Date 2013 vs. 2012 Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	(15	)	$	24
Other		3			(3	)
Rate adjustment clause equity return		2			32
PJM ancillary services		(9	)		(21	)
Outage costs		(12	)		9
Other		10			12

Change in net income contribution	$	(21	)	$	53

Corporate and Other

Liquidity and Capital Resources

Dominion and Virginia Power depend on both internal and external sources of liquidity to provide working capital and as a bridge to long-term debt financings. 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.

PAGE 73

At September 30, 2013, Dominion had $1.3 billion of unused capacity under its credit facilities, including $764 million of unused capacity under joint credit facilities available to Virginia Power.

The dispositions of certain merchant generation facilities during 2012 and the decommissioning and sale of certain other merchant generation facilities in 2013 are not expected to have a material negative impact on Dominion’s liquidity.

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


	2013			2012
(millions)
Cash and cash equivalents at January 1	$	248		$	102
Cash flows provided by (used in):
Operating activities		2,950			3,462
Investing activities		(2,348	)		(2,784	)
Financing activities		(563	)		(699	)

Net increase (decrease) in cash and cash equivalents		39			(21	)

Cash and cash equivalents at September 30	$	287		$	81

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


	2013			2012
(millions)
Cash and cash equivalents at January 1	$	28		$	29
Cash flows provided by (used in):
Operating activities		2,036			2,287
Investing activities		(1,948	)		(1,551	)
Financing activities		(65	)		(744	)

Net increase (decrease) in cash and cash equivalents		23			(8	)

Cash and cash equivalents at September 30	$	51		$	21

Operating Cash Flows

Net cash provided by Dominion’s operating activities decreased $512 million, primarily due to lower deferred fuel cost recoveries in its Virginia jurisdiction, higher net margin collateral requirements, higher income tax payments, and lower margins from retail energy marketing activities and merchant generation operations. The decrease was partially offset by lower rate refund payments and an increase in regulated natural gas transmission operations.

Net cash provided by Virginia Power’s operating activities decreased by $251 million, primarily due to lower deferred fuel cost recoveries, partially offset by lower rate refund payments.

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, 2012 and in Part II, Item 1A. Risk Factors in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013.

PAGE 74

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, 2013 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⁾	$	90	$	—	$	90
Non-investment grade⁽²⁾		27		—		27
No external ratings:
Internally rated - investment grade⁽³⁾		39		—		39
Internally rated - non-investment grade⁽⁴⁾		49		—		49

Total	$	205	$	—	$	205

(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 24% of the total net credit exposure.

(2)	The five largest counterparty exposures, combined, for this category represented approximately 9% of the total net credit exposure.

(3)	The five largest counterparty exposures, combined, for this category represented approximately 13% of the total net credit exposure.

(4)	The five largest counterparty exposures, combined, for this category represented approximately 6% of the total net credit exposure.

Investing Cash Flows

Net cash used in Dominion’s investing activities decreased $436 million, primarily due to the proceeds from the sale of Brayton Point, Kincaid, and equity method investment in Elwood and the net proceeds from the sale of assets to Blue Racer, partially offset by higher capital expenditures.

Net cash used in Virginia Power’s investing activities increased $397 million, primarily due to higher capital expenditures.

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 MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2012, 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.

In 2013, net cash used in Dominion’s financing activities decreased $136 million, primarily reflecting higher net debt issuances, partially offset by the acquisition of the Juniper noncontrolling interest in Fairless and higher common dividend payments.

Net cash used in Virginia Power’s financing activities decreased $679 million, primarily due to net debt issuances in 2013 as compared to net debt repayments in 2012, partially offset by higher common dividend payments.

In June 2013, Dominion issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B 6% Equity Units, initially in the form of Corporate Units. Dominion used the net proceeds from the sale of Equity Units for general corporate purposes, including repayment of short-term debt, and to fund its growth plan, including the Cove Point liquefaction project. Dominion intends to use the proceeds from the settlement of the stock purchase contracts to repay debt issued, or displace debt that may otherwise be issued, in part to fund capital expenditures or for other corporate purposes as soon as practicable following such settlement. 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.

PAGE 75

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 October 2013, Standard & Poor’s affirmed Dominion’s corporate credit rating of A- but lowered the rating for Dominion’s senior unsecured debt securities to BBB+ from A- to reflect greater structural subordination at Dominion due to new debt at DGH. Also in October 2013, Fitch, Moody’s and Standard & Poor’s assigned a BBB+, A3 and A- rating, respectively, to the senior unsecured notes at DGH. See Note 14 in this report for more information.

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, 2012, there is a discussion on the various covenants present in the enabling agreements underlying the Companies’ debt. As of September 30, 2013, 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, 2013, there have been no material changes outside the ordinary course of business to Dominion’s or Virginia Power’s contractual obligations as disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2012.

As of September 30, 2013, Dominion’s planned capital expenditures for 2013, 2014 and 2015 are expected to total approximately $5.1 billion, $5.1 billion and $4.3 billion, respectively. The increase in planned capital expenditures, as compared to the amounts originally forecasted in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2012, primarily reflects the planned construction of the Cove Point liquefaction project in Maryland. There have been no material changes to Virginia Power’s planned capital expenditures.

Use of Off-Balance Sheet Arrangements

As of September 30, 2013, 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, 2012.

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 MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2012 and Future Issues and Other Matters in MD&A in Dominion’s and Virginia Power’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013.

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 22 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2012, and Note 15 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013 and in this report for additional information on various environmental matters.

Climate Change Legislation and Regulation

In April 2012, the EPA published proposed NSPS for GHG emissions for new electric and generating units. This proposed rule set national emission standards for new coal, oil, integrated gasification, and combined cycle units larger than 25MW. The proposed rule covered CO₂ only and does not apply to existing sources. The proposed rule also does not apply to any new or existing simple cycle combustion turbine units or biomass units. In June 2013, the President of the U.S. released a Climate Action Plan focusing on ways to meet the national GHG reduction goal of 17% from 2005 levels by 2020. Pursuant to the Presidential Memorandum issued in conjunction with the Climate Action Plan and based on over 2.5 million comments received, the EPA re-proposed the NSPS standards for new sources in September 2013 and is expected to finalize the rule by June 2014. The EPA is expected to officially withdraw the 2012 new source proposal on the same day the re-proposed rule is issued in the Federal Register. The Presidential Memorandum also directed the EPA to propose a rule for reconstructed, modified and existing sources no later than June 2014, and issue a final rule no later than June 2015, to provide guidelines to the states to achieve the required GHG reductions. Dominion currently cannot predict with certainty the direct or indirect financial impact on operations from these rule revisions, but believes the expenditures to comply with any new requirements could be material.

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On October 15, 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the Chamber of Commerce seeking review of the D.C. Circuit Court’s June 2012 decision upholding the EPA’s regulation of GHG under the CAA. The court’s decision could potentially impact the EPA’s continued implementation of current Prevention of Significant Deterioration regulations applicable to stationary sources in relation to GHG. It is not anticipated, however, that the court’s decision would affect the EPA’s development of the GHG NSPS rules for new sources, or existing sources, as the authority for those rules comes from a different section of the CAA than what is at issue in the Supreme Court case. It is uncertain at this time whether the court’s decision will have any material impact on Dominion’s operations.

Regulatory Matters

See Note 13 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2012 and Note 12 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013, June 30, 2013 and in this report for additional information on various regulatory matters.

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, 2012, Notes 12 and 15 to the Consolidated Financial Statements and Part II, Item 1. Legal Proceedings in Dominion’s and Virginia Power’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013, June 30, 2013 and in this report for additional information on various legal matters.

Cove Point Liquefaction Project

Dominion is pursuing a liquefaction project at Cove Point, which would enable the facility to liquefy domestically-produced natural gas for export as LNG. In September 2013, the DOE conditionally authorized Dominion to export LNG from Cove Point to non-free trade agreement countries. Subject to environmental review by FERC and final FERC approval, the Cove Point facility is authorized to export at a rate of 770 million cubic feet of natural gas per day for a period of 20 years. The DOE previously authorized Dominion to export to countries with free trade agreements. Following receipt of regulatory and other approvals, construction of liquefaction facilities could begin in 2014 with an in-service date in 2017.

Master Limited Partnership Plans

In September 2013, Dominion announced its plans to form an MLP in 2014 by contributing certain of its midstream natural gas assets to the MLP initially and over time. Dominion is currently considering assets other than those owned by DGH, including interests in Cove Point and Dominion’s share of the Blue Racer joint venture.

Marcellus Shale

In October 2013, DTI signed agreements with two counterparties to assign lease rights for approximately 90,000 acres of Marcellus shale rights underneath several of its gas storage fields. The agreements provide for payments to DTI, subject to customary adjustments, of approximately $190 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. The assignments are expected to close in the fourth quarter of 2013. Dominion continues to receive indications of interest in its Marcellus Shale acreage and expects to conclude similar transactions in the fourth quarter of 2013 and in 2014.

New Market Project

In September 2013, DTI executed binding precedent agreements with several local distribution company customers for the New Market Project. The project is expected to provide 112,000 dekatherms per day of firm transportation service from Leidy, Pennsylvania to interconnects with Iroquois Gas Transmission and Niagara Mohawk Power Corporation’s distribution system in the Albany, New York market. In 2014, DTI expects to file an application to request FERC authorization to construct and operate the project facilities, which are expected to be in service in the fourth quarter of 2016.

Western Access Project

East Ohio has signed long term precedent agreements with two customers to move processed gas from the outlet of new gas processing facilities to interconnections with multiple interstate pipelines. System enhancements are expected to be complete by November 1, 2014, and are anticipated to total $90 million.

Virginia Offshore Wind

Virginia Power is developing a commercial offshore wind generation project. In December 2012, BOEM announced that, in 2013, it would auction approximately 113,000 acres of federal land off the Virginia coast as a single lease for construction of offshore wind turbines. During the third quarter of 2013, Virginia Power bid $1.6 million and won the lease, which would allow for development of an offshore wind turbine farm capable of generating up to 2,000 MW of electricity. BOEM has several milestones that Virginia Power must meet to keep the lease with the final milestone being the submittal of a construction and operations plan within five years of signing the lease. Once Virginia Power submits a plan, BOEM has an undetermined amount of time to perform an environmental analysis and approve the plan. Subject to a final decision on pursuing the project, construction would be contingent on the receipt of applicable approvals.

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Solar Investment Fund

In 2012, Dominion formed Tredegar Solar Fund I, an entity managed by Dominion’s Alternative Energy Solutions group and focused on unregulated residential solar projects. The Fund owns residential roof-top solar systems that are originated and administered by Clean Power Finance, Inc., a provider of solar finance products, in which Dominion has a small indirect equity investment. The systems are subject to power purchase agreements with third parties. In September 2013, Dominion’s BOD approved an incremental investment in the Fund, for a total authorized investment of $55 million. The Fund has originations in process of approximately $38 million and assets in service of approximately $9 million as of October 2013.

Electric Transmission Projects

Loudoun-Pleasant View Rebuild Project

In October 2013, Virginia Power filed an application with the Virginia Commission for the rebuild of the existing 500 kV Loudoun-Pleasant View Line in Loudoun County, Virginia. This project, which is estimated to cost $31 million and to be in service by June 2016, is intended to address projected NERC reliability criteria matters and to replace aging infrastructure.

Pleasant View Capacitor Bank Expansion

In August 2013, the Virginia Commission issued a final order granting Virginia Power’s request for a CPCN to construct and operate the Pleasant View Capacitor Bank Expansion project. Specifically, the Virginia Commission authorized Virginia Power to build the new Goose Creek 500 kV switching station and the new Pleasant View-to-Goose Creek 500 kV transmission line, and to reconfigure the existing Pleasant View-to-Brambleton and Pleasant View-to-Doubs 500 kV transmission lines to connect to this new switching station, along with additional facilities related to the project. The estimated total project cost according to Virginia Power’s application was approximately $16 million. The Virginia Commission’s approval order notes that the project will occur entirely on property owned by Virginia Power, and states that all work must be done by June 1, 2014, although this deadline can be extended for good cause shown.

PJM - RTEP Projects

As part of PJM’s annual RTEP process, in October 2013, PJM authorized the following electric transmission reliability projects:

•

The addition of four 230 kV variable shunt reactor banks at Virginia Power’s existing Clifton, Braddock, Garrisonville and Virginia Hills switching stations in northern Virginia. This project is estimated to cost $24 million, and to be in service by October 1, 2014. Virginia Commission approval is not required;

•

The construction of a new Scott’s Run switching station in northern Virginia, along with a new 4.5-mile, 230 kV overhead line between this station and Virginia Power’s Idylwood station. Virginia Power expects to request the Virginia Commission’s approval of this approximately $32 million project in the second quarter of 2014; and

•

The construction of a new 39-mile, 230 kV overhead line on single structures between Virginia Power’s existing Lexington and Dooms stations, to supplement the rebuilt 500 kV line approved by the Virginia Commission in May 2013. Virginia Power expects to request the Virginia Commission’s approval of this approximately $14 million project in November 2013.

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 analyses estimate 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.

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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.

In the second quarter of 2013, Dominion commenced a restructuring of its producer services business, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates. The restructuring will result in the termination of natural gas trading and certain energy marketing activities. The restructuring is intended to reduce producer services’ earnings volatility, and is not expected to have a material impact on Dominion’s business.

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 $162 million and $126 million as of September 30, 2013 and December 31, 2012, 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 $8 million and $18 million as of September 30, 2013 and December 31, 2012, 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, 2013 or December 31, 2012.

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 earnings at September 30, 2013 or December 31, 2012.

Dominion and Virginia Power may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. As of September 30, 2013, Dominion and Virginia Power had $1.8 billion and $600 million, 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 $30 million and $12 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at September 30, 2013. As of December 31, 2012, Dominion and Virginia Power had $1.8 billion and $750 million, 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 $21 million and $9 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at December 31, 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 gains and/or 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.

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Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $126 million, $87 million and $126 million for the nine months ended September 30, 2013 and 2012 and for the year ended December 31, 2012, 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 $225 million, $239 million and $210 million for the nine months ended September 30, 2013 and 2012 and for the year ended December 31, 2012, respectively.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $36 million, $32 million and $53 million for the nine months ended September 30, 2013 and 2012 and for the year ended December 31, 2012, 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 $116 million, $101 million and $89 million for the nine months ended September 30, 2013 and 2012 and for the year ended December 31, 2012, respectively.

Dominion sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power employees participate in these plans. 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.

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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 matters 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, 2012.

In June 2013, DTI received a draft Consent Assessment of Civil Penalty from the PADEP in connection with an accidental release from a leaking underground pipe at one of DTI’s compressor stations in Pennsylvania. DTI self reported the release in December 2011 and promptly conducted remediation. In August 2013, DTI and PADEP agreed to a Consent Assessment that included a penalty of $192,000, which DTI has paid. The resolution of the Consent Assessment is not expected to have a material effect on Dominion.

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

•

Notes 13 and 22 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, 2012.

•

Notes 12 and 15 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013, and 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, 2012, 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, 2012 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2013. 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⁾
7/1/13-7/31/13		2,430	$	56.24		—	19,629,059 shares/ $1.18 billion
8/1/13-8/31/13		—		—		—	19,629,059 shares/ $1.18 billion
9/1/13-9/30/13		13,271		58.35		—	19,629,059 shares/ $1.18 billion

Total		15,701	$	58.02		—	19,629,059 shares/ $1.18 billion

(1)	In July and September 2013, 2,430 shares and 13,271 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 filed April 29, 2011, File No. 1-2255).		X

3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective May 3, 2013 (Exhibit 3.1, Form 8-K filed May 3, 2013, 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

4.1	Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company 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 February 27, 1998, File No. 333-47119); Form of First Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Eleventh Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255); Forms of Twelfth and Thirteenth Supplemental Indentures, dated January 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Forms of Sixteenth and Seventeenth Supplemental Indentures, dated November 1, 2007 (Exhibits 4.2 and 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255).	X	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

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

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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, 2013, filed on November 5, 2013, 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

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SIGNATURE

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


				DOMINION RESOURCES, INC.
				Registrant

November 5, 2013				/s/ Ashwini Sawhney
				Ashwini Sawhney Vice President – Accounting and Controller (Chief Accounting Officer)

				VIRGINIA ELECTRIC AND POWER COMPANY
				Registrant

November 5, 2013				/s/ Ashwini Sawhney
				Ashwini Sawhney Vice President – Accounting (Chief Accounting Officer)

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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 filed April 29, 2011, File No. 1-2255).		X

3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective May 3, 2013 (Exhibit 3.1, Form 8-K filed May 3, 2013, 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

4.1	Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company 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 February 27, 1998, File No. 333-47119); Form of First Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Eleventh Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255); Forms of Twelfth and Thirteenth Supplemental Indentures, dated January 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Forms of Sixteenth and Seventeenth Supplemental Indentures, dated November 1, 2007 (Exhibits 4.2 and 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255).	X	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

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

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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, 2013, filed on November 5, 2013, 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

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