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, 2011

or

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

For the transition period from              to             

Commission File Number	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.

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

Virginia Electric and Power Company

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

Indicate by check mark whether the registrant is a shell company (as defined 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, 2011, the latest practicable date for determination, Dominion Resources, Inc. had 569,611,030 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		PAGE 3
	PART I. Financial Information
Item 1.	Financial Statements		PAGE 6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		PAGE 49
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		PAGE 65
Item 4.	Controls and Procedures		PAGE 66
	PART II. Other Information
Item 1.	Legal Proceedings		PAGE 66
Item 1A.	Risk Factors		PAGE 67
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		PAGE 67
Item 6.	Exhibits		PAGE 68

PAGE 2

GLOSSARY OF TERMS

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

Abbreviation or Acronym	Definition
2009 Base Rate Review	Order entered by the Virginia Commission in January 2009, pursuant to the Regulation Act, initiating reviews of the base rates and terms and conditions of all investor-owned utilities in Virginia
AFUDC	Allowance for funds used during construction
AOCI	Accumulated other comprehensive income (loss)
ARO	Asset retirement obligation
ARP	Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the CAA
ASLB	Atomic Safety and Licensing Board
bcf	Billion cubic feet
Bear Garden	A 580 MW combined cycle, natural gas-fired power station in Buckingham County, Virginia
Brayton Point	Brayton Point power station
BREDL	Blue Ridge Environmental Defense League
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CEO	Chief Executive Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
CFO	Chief Financial Officer
CO2	Carbon dioxide
COL	Combined Construction Permit and Operating License
Companies	Dominion and Virginia Power, collectively
CONSOL	CONSOL Energy, Inc.
Cooling degree days	Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
Cove Point	Dominion Cove Point LNG, LP
CSAPR	Cross State Air Pollution Rule
CWA	Clean Water Act
DEI	Dominion Energy, Inc.
DOE	Department of Energy
Dominion	The legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries (other than Virginia Power) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries
Dominion Direct®	A dividend reinvestment and open enrollment direct stock purchase plan
DRS	Dominion Resources Services, Inc.
DSM	Demand-side management
DTI	Dominion Transmission, Inc.
DVP	Dominion Virginia Power operating segment
East Ohio	The East Ohio Gas Company, doing business as Dominion East Ohio
E&P	Exploration & production
EPA	Environmental Protection Agency
EPS	Earnings per share

PAGE 3

Abbreviation or Acronym	Definition
Fairless	Fairless power station
FERC	Federal Energy Regulatory Commission
Fowler Ridge	A wind-turbine facility joint venture between Dominion and BP Alternative Energy, Inc. in Benton County, Indiana
FTRs	Financial transmission rights
GAAP	U.S. generally accepted accounting principles
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
IRP	Integrated Resource Plan
ISO	Independent system operator
June 2006 hybrids	2006 Series A Enhanced Junior Subordinated Notes due 2066
Juniper	Juniper Capital L.P.
Kewaunee	Kewaunee nuclear power station
Kincaid	Kincaid power station
LNG	Liquefied natural gas
Local 12502	United Steelworkers, Local 12502
Local G-555	The Gas Workers Union, Local G-555, Utility Workers Union of America, AFL-CIO
Manchester Street	Manchester Street power station
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Medicare Act	The Medicare Prescription Drug, Improvement and Modernization Act of 2003
Medicare Part D	Prescription drug benefit introduced in the Medicare Act
Millstone	Millstone nuclear power station
Moody’s	Moody’s Investors Service
Mt. Storm-to-Doubs line	Virginia Power project to rebuild approximately 96 miles of an existing 500-kilovolt transmission line in Virginia and West Virginia
MW	Megawatt
MWh	Megawatt hour
NAAQS	National Ambient Air Quality Standard
NedPower	A wind-turbine facility joint venture between Dominion and Shell WindEnergy Inc. in Grant County, West Virginia
NGLs	Natural gas liquids
NHSM	Non-hazardous secondary material
North Anna	North Anna nuclear power station
North Carolina Commission	North Carolina Utilities Commission
NOX	Nitrogen oxide
NPDES	National Pollutant Discharge Elimination System
NRC	Nuclear Regulatory Commission
ODEC	Old Dominion Electric Cooperative
Ohio Commission	Public Utilities Commission of Ohio

PAGE 4

Abbreviation or Acronym	Definition
OPEB	Other Postretirement Employee Benefits
Peoples	The Peoples Natural Gas Company
PIR	Pipeline Infrastructure Replacement program deployed by East Ohio
PJM	PJM Interconnection, LLC
PNG Companies LLC	An indirect subsidiary of SteelRiver Infrastructure Fund North America
RCCs	Replacement Capital Covenants
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 B	A rate adjustment clause associated with the recovery of costs related to the proposed conversion of three of Virginia Power’s coal-fired power stations to biomass
Rider R	A rate adjustment clause associated with the recovery of costs related to Bear Garden
Rider S	A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center
Rider W	A rate adjustment clause associated with the recovery of costs related to the proposed Warren County, Virginia Power Station
	Rate adjustment clauses associated with the recovery of costs related to certain DSM programs
ROE	Return on equity
RPS	Renewable Portfolio Standard
RTO	Regional transmission organization
Salem Harbor	Salem Harbor power station
SEC	Securities and Exchange Commission
September 2006 hybrids	2006 Series B Enhanced Junior Subordinated Notes due 2066
SO2	Sulfur dioxide
Standard & Poor’s	Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
State Line	State Line power station
Surry	Surry nuclear power station
TGP	Tennessee Gas Pipeline
U.S.	United States of America
UAO	Unilateral Administrative Order
VIE	Variable interest entity
Virginia City Hybrid Energy Center	A 585 MW baseload carbon-capture compatible, clean coal powered electric generation facility under construction in Wise County, Virginia
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
Virginia Settlement Approval Order	Order issued by the Virginia Commission in March 2010 concluding Virginia Power’s 2009 Base Rate Review
VPDES	Virginia Pollutant Discharge Elimination System
VSWCB	Virginia State Water Control Board
Yorktown	Yorktown power station

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,
	2011		2010		2011		2010
(millions, except per share amounts)
Operating Revenue	$	3,803	$	3,950	$	11,201	$	11,451
Operating Expenses
Electric fuel and other energy-related purchases		1,243		1,180		3,270		3,164
Purchased electric capacity		109		116		344		333
Purchased gas		335		367		1,342		1,550
Other operations and maintenance		885		788		2,523		2,709
Depreciation, depletion and amortization		268		263		785		794
Other taxes		130		117		416		405
Total operating expenses		2,970		2,831		8,680		8,955
Gain on sale of Appalachian E&P operations		—		—		—		2,467
Income from operations		833		1,119		2,521		4,963
Other income		16		63		112		109
Interest and related charges		249		229		692		600
Income from continuing operations including noncontrolling interests before income tax expense		600		953		1,941		4,472
Income tax expense		204		374		722		1,803
Income from continuing operations including noncontrolling interests		396		579		1,219		2,669
Loss from discontinued operations(1)		—		—		—		(147	)
Net Income Including Noncontrolling Interests		396		579		1,219		2,522
Noncontrolling Interests		4		4		12		12
Net Income Attributable to Dominion	$	392	$	575	$	1,207	$	2,510
Amounts Attributable to Dominion:
Income from continuing operations, net of tax	$	392	$	575	$	1,207	$	2,657
Loss from discontinued operations, net of tax		—		—		—		(147	)
Net income attributable to Dominion	$	392	$	575	$	1,207	$	2,510
Earnings Per Common Share – Basic
Income from continuing operations	$	0.69	$	0.98	$	2.10	$	4.49
Loss from discontinued operations		—		—		—		(0.25	)
Net income attributable to Dominion	$	0.69	$	0.98	$	2.10	$	4.24
Earnings Per Common Share – Diluted
Income from continuing operations	$	0.69	$	0.98	$	2.10	$	4.48
Loss from discontinued operations		—		—		—		(0.25	)
Net income attributable to Dominion	$	0.69	$	0.98	$	2.10	$	4.23
Dividends declared per common share	$	0.4925	$	0.4575	$	1.4775	$	1.3725

(1) Includes income tax expense of $13 million for the nine months ended September 30, 2010.

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

PAGE 6

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011			December  31, 2010(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	212		$	62
Customer receivables (less allowance for doubtful accounts of $28 and $26)		1,646			2,158
Other receivables (less allowance for doubtful accounts of $8 and $9)		228			88
Inventories		1,326			1,163
Derivative assets		598			739
Other		1,257			1,190
Total current assets		5,267			5,400
Investments
Nuclear decommissioning trust funds		2,799			2,897
Investment in equity method affiliates		559			571
Restricted cash equivalents		204			400
Other		290			283
Total investments		3,852			4,151
Property, Plant and Equipment
Property, plant and equipment		42,155			39,855
Accumulated depreciation, depletion and amortization		(13,744	)		(13,142	)
Total property, plant and equipment, net		28,411			26,713
Deferred Charges and Other Assets
Goodwill		3,141			3,141
Regulatory assets		1,410			1,446
Other		1,949			1,966
Total deferred charges and other assets		6,500			6,553
Total assets	$	44,030		$	42,817

(1) Dominion’s Consolidated Balance Sheet at December 31, 2010 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 7

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	September 30, 2011			December  31, 2010(1)
(millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Securities due within one year	$	1,327		$	497
Short-term debt		783			1,386
Accounts payable		1,138			1,562
Accrued interest, payroll and taxes		647			849
Other		1,601			1,479
Total current liabilities		5,496			5,773
Long-Term Debt
Long-term debt		15,418			14,023
Junior subordinated notes payable to affiliates		268			268
Enhanced junior subordinated notes		1,467			1,467
Total long-term debt		17,153			15,758
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		5,130			4,708
Asset retirement obligations		1,654			1,577
Regulatory liabilities		1,251			1,392
Other		1,457			1,355
Total deferred credits and other liabilities		9,492			9,032
Total liabilities		32,141			30,563
Commitments and Contingencies (see Note 15)
Subsidiary Preferred Stock Not Subject to Mandatory Redemption		257			257
Common Shareholders’ Equity
Common stock – no par(2)		5,171			5,715
Other paid-in capital		182			194
Retained earnings		6,778			6,418
Accumulated other comprehensive loss		(499	)		(330	)
Total common shareholders’ equity		11,632			11,997
Total liabilities and shareholders’ equity	$	44,030		$	42,817

(1) Dominion’s Consolidated Balance Sheet at December 31, 2010 has been derived from the audited Consolidated Financial Statements at that date.

(2) 1 billion shares authorized; 570 million and 581 million shares outstanding at September 30, 2011 and December 31, 2010, respectively.

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

PAGE 8

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

Nine Months Ended September 30,	2011			2010
(millions)
Operating Activities
Net income including noncontrolling interests	$	1,219		$	2,522
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Gain from sale of Appalachian E&P operations		—			(2,467	)
Loss from sale of Peoples		—			113
Charges (payments) related to workforce reduction program		(93	)		261
Impairment of merchant generation facility		55			163
Depreciation, depletion and amortization (including nuclear fuel)		951			946
Deferred income taxes and investment tax credits		643			310
Contribution to employee pension plans		—			(250	)
Rate refunds		(64	)		(413	)
Other adjustments		(3	)		(20	)
Changes in:
Accounts receivable		527			360
Inventories		(162	)		(23	)
Deferred fuel and purchased gas costs		(60	)		(147	)
Prepayments		(53	)		274
Accounts payable		(419	)		(51	)
Accrued interest, payroll and taxes		(201	)		270
Margin deposit assets and liabilities		(92	)		(23	)
Other operating assets and liabilities		150			59
Net cash provided by operating activities		2,398			1,884
Investing Activities
Plant construction and other property additions		(2,616	)		(2,509	)
Proceeds from the sale of Appalachian E&P operations		—			3,450
Proceeds from the sale of Peoples		—			741
Proceeds from sale of securities		1,404			1,938
Purchases of securities		(1,459	)		(2,470	)
Restricted cash equivalents		196			—
Other		111			75
Net cash provided by (used in) investing activities		(2,364	)		1,225
Financing Activities
Repayment of short-term debt, net		(602	)		(1,195	)
Issuance and remarketing of long-term debt		2,245			550
Repayment of long-term debt		(74	)		(414	)
Issuance of common stock		37			66
Repurchase of common stock		(601	)		(900	)
Common dividend payments		(848	)		(810	)
Subsidiary preferred dividend payments		(12	)		(12	)
Other		(29	)		2
Net cash provided by (used in) financing activities		116			(2,713	)
Increase in cash and cash equivalents		150			396
Cash and cash equivalents at beginning of period		62			50
Cash and cash equivalents at end of period	$	212		$	446
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	237		$	192

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

PAGE 9

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions)
Operating Revenue	$	2,177	$	2,111	$	5,691	$	5,561
Operating Expenses
Electric fuel and other energy-related purchases		746		694		1,922		1,915
Purchased electric capacity		108		116		342		331
Other operations and maintenance:
Affiliated suppliers		79		85		229		293
Other		435		319		943		947
Depreciation and amortization		184		171		533		499
Other taxes		57		53		172		170
Total operating expenses		1,609		1,438		4,141		4,155
Income from operations		568		673		1,550		1,406
Other income		25		25		64		67
Interest and related charges		114		88		290		259
Income before income tax expense		479		610		1,324		1,214
Income tax expense		182		230		508		472
Net Income		297		380		816		742
Preferred dividends		4		4		12		12
Balance available for common stock	$	293	$	376	$	804	$	730

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

PAGE 10

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	24		$	5
Customer receivables (less allowance for doubtful accounts of $11 at both dates)		964			905
Other receivables (less allowance for doubtful accounts of $8 and $6)		137			54
Inventories (average cost method)		732			597
Prepayments		71			65
Other		450			355
Total current assets		2,378			1,981
Investments
Nuclear decommissioning trust funds		1,285			1,319
Restricted cash equivalents		38			169
Other		3			4
Total investments		1,326			1,492
Property, Plant and Equipment
Property, plant and equipment		28,986			27,607
Accumulated depreciation and amortization		(10,088	)		(9,712	)
Total property, plant and equipment, net		18,898			17,895
Deferred Charges and Other Assets
Intangible assets		176			212
Regulatory assets		387			370
Other		130			312
Total deferred charges and other assets		693			894
Total assets	$	23,295		$	22,262

(1) Virginia Power’s Consolidated Balance Sheet at December 31, 2010 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 11

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	September 30, 2011		December  31, 2010(1)
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	15	$	15
Short-term debt		550		600
Accounts payable		455		499
Payables to affiliates		84		76
Affiliated current borrowings		215		103
Accrued interest, payroll and taxes		287		214
Other		651		571
Total current liabilities		2,257		2,078
Long-Term Debt		6,853		6,702
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		3,074		2,672
Asset retirement obligations		705		669
Regulatory liabilities		1,029		1,174
Other		266		203
Total deferred credits and other liabilities		5,074		4,718
Total liabilities		14,184		13,498
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		1,111		1,111
Retained earnings		1,990		1,634
Accumulated other comprehensive income		15		24
Total common shareholder’s equity		8,854		8,507
Total liabilities and shareholder’s equity	$	23,295	$	22,262

(1) Virginia Power’s Consolidated Balance Sheet at December 31, 2010 has been derived from the audited Consolidated Financial Statements at that date.

(2) 500,000 shares and 300,000 shares authorized at September 30, 2011 and December 31, 2010, respectively; 274,723 shares outstanding at both September 30, 2011 and December 31, 2010.

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

PAGE 12

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended September 30,	2011			2010
(millions)
Operating Activities
Net income	$	816		$	742
Adjustments to reconcile net income to net cash provided by operating activities:
Charges (payments) related to workforce reduction program		(41	)		98
Depreciation and amortization (including nuclear fuel)		625			584
Deferred income taxes and investment tax credits		449			399
Rate refunds		(64	)		(413	)
Contribution to employee pension plans		—			(119	)
Other adjustments		9			(32	)
Changes in:
Accounts receivable		14			(38	)
Affiliated accounts receivable and payable		7			1
Inventories		(135	)		10
Deferred fuel expenses		(58	)		(126	)
Accounts payable		6			80
Accrued interest, payroll and taxes		72			66
Prepayments		(6	)		(62	)
Other operating assets and liabilities		3			48
Net cash provided by operating activities		1,697			1,238
Investing Activities
Plant construction and other property additions		(1,392	)		(1,579	)
Purchases of nuclear fuel		(169	)		(114	)
Purchases of securities		(850	)		(976	)
Proceeds from sales of securities		838			959
Restricted cash equivalents		131			—
Other		11			2
Net cash used in investing activities		(1,431	)		(1,708	)
Financing Activities
Repayment of short-term debt, net		(50	)		(342	)
Issuance of affiliated current borrowings, net		112			897
Remarketing/issuance of long-term debt		160			300
Repayment of long-term debt		(10	)		(11	)
Common dividend payments		(448	)		(360	)
Preferred dividend payments		(12	)		(12	)
Other		1			1
Net cash provided by (used in) financing activities		(247	)		473
Increase in cash and cash equivalents		19			3
Cash and cash equivalents at beginning of period		5			19
Cash and cash equivalents at end of period	$	24		$	22
Supplemental Cash Flow Information
Significant noncash investing and financing activities:
Accrued capital expenditures	$	86		$	114
Settlement of debt and issuance of common stock to Dominion		—			636

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

PAGE 13

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, 2010 and their Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

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, 2011, their results of operations for the three and nine months ended September 30, 2011 and 2010 and their cash flows for the nine months ended September 30, 2011 and 2010. 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.

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 2010 Consolidated Financial Statements and Notes have been reclassified to conform to the 2011 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, shareholders’ equity or cash flows.

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

Note 3. Dispositions

Sale of Appalachian E&P Operations

In April 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. The transaction included the mineral rights to approximately 491,000 acres in the Marcellus Shale formation. Dominion retained certain oil and natural gas wells located on or near its natural gas storage fields. The transaction generated after-tax proceeds of approximately $2.2 billion and resulted in an after-tax gain of approximately $1.4 billion, which included a $134 million write-off of goodwill, recorded in the second quarter of 2010.

The results of operations for Dominion’s Appalachian E&P business are not reported as discontinued operations in the Consolidated Statements of Income since Dominion did not sell its entire U.S. cost pool.

Due to the sale, hedge accounting was discontinued for certain cash flow hedges since it became probable that the forecasted sales of natural gas would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a $42 million ($25 million after-tax) benefit, recorded in operating revenue in its Consolidated Statement of Income, reflecting the reclassification of gains from AOCI to earnings for these contracts in March 2010.

PAGE 14

Sale of Peoples

In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The sale resulted in an after-tax loss of approximately $140 million, including post-closing adjustments, and a $79 million write-off of goodwill. The sale also resulted in after-tax expenses of approximately $27 million, including transaction and benefit-related costs. Prior to the sale, Peoples had income from operations of $12 million after-tax during 2010.

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

	Three Months  Ended September 30, 2010		Nine Months  Ended September 30, 2010
(millions)
Operating revenue	$	—	$	67
Income (loss) before income taxes		—		(134	)

Note 4. Ceiling Test

Dominion follows the full cost method of accounting for its gas and oil E&P activities, which subjects capitalized costs to a quarterly ceiling test using hedge-adjusted prices. Due to the April 2010 sale of substantially all of its Appalachian E&P operations, as of September 30, 2011, Dominion no longer has any significant gas and oil properties subject to the ceiling test calculation.

At March 31, 2010, Dominion recorded a ceiling test impairment charge of $21 million ($13 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income primarily due to a decline in hedge-adjusted prices reflecting the discontinuance of hedge accounting for certain cash flow hedges, as discussed in Note 3.

Note 5. Operating Revenue

The Companies’ operating revenue consists of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions)
Dominion
Electric sales:
Regulated	$	2,136	$	2,083	$	5,594	$	5,488
Nonregulated		915		1,072		2,650		2,857
Gas sales:
Regulated		25		25		208		209
Nonregulated		281		375		1,220		1,502
Gas transportation and storage		291		289		1,151		1,070
Other		155		106		378		325
Total operating revenue	$	3,803	$	3,950	$	11,201	$	11,451
Virginia Power
Regulated electric sales	$	2,136	$	2,083	$	5,594	$	5,488
Other		41		28		97		73
Total operating revenue	$	2,177	$	2,111	$	5,691	$	5,561

PAGE 15

Note 6. Income Taxes

Continuing Operations

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

	Dominion						Virginia Power
Nine Months Ended September 30,	2011			2010			2011			2010
U.S. statutory rate		35.0	%		35.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		3.6			4.5			3.9			3.9
Legislative changes		—			1.2			—			1.3
Other, net		(1.4	)		(0.4	)		(0.5	)		(1.3	)
Effective tax rate		37.2	%		40.3	%		38.4	%		38.9	%

Dominion’s and Virginia Power’s effective tax rates in 2010 reflect the reduction of deferred tax assets resulting from the enactment of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act of 2010 which eliminated the employer’s deduction, beginning in 2013, for that portion of its retiree prescription drug coverage cost that is being reimbursed by the Medicare Part D subsidy. In addition, Dominion’s effective tax rate in 2010 reflects higher state income taxes due to the sale of its Appalachian E&P operations.

See Note 6 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010, for a discussion of the Companies’ unrecognized tax benefits. During the nine months ended September 30, 2011, Dominion’s and Virginia Power’s unrecognized tax benefits changed as follows:

	Dominion			Virginia Power
(millions)
Balance at January 1, 2011	$	307		$	117
Increases – prior period positions		24			17
Decreases – prior period positions		(53	)		(33	)
Current period positions		41			23
Balance at September 30, 2011	$	319		$	124

With the expiration of statutes of limitations, completion of audits and possible settlements with tax authorities, it is reasonably possible that unrecognized tax benefits could decrease during the next 12 months by up to $60 million for Dominion and up to $30 million for Virginia Power. In addition, based on Dominion’s decision in October 2011 to file tax refund claims involving uncertainty in the reporting of asset dispositions, unrecognized tax benefits increased by $96 million.

Discontinued Operations

Income tax expense in 2010 for Dominion’s discontinued operations primarily reflects the impact of goodwill written off in the sale of Peoples that is not deductible for tax purposes and the reversal of deferred taxes for which the benefit was offset by the reversal of income tax-related regulatory assets.

PAGE 16

Note 7. 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,
	2011		2010		2011		2010
(millions, except EPS)
Net income attributable to Dominion	$	392	$	575	$	1,207	$	2,510
Average shares of common stock outstanding – Basic		569.4		585.0		574.2		591.7
Net effect of potentially dilutive securities(1)		1.8		1.4		1.4		1.1
Average shares of common stock outstanding – Diluted		571.2		586.4		575.6		592.8
Earnings Per Common Share – Basic	$	0.69	$	0.98	$	2.10	$	4.24
Earnings Per Common Share – Diluted	$	0.69	$	0.98	$	2.10	$	4.23

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

There were no potentially dilutive securities excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2011 and 2010.

Note 8. Comprehensive Income

The following table presents Dominion’s total comprehensive income:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Net income including noncontrolling interests	$	396		$	579		$	1,219		$	2,522
Other comprehensive income (loss):
Net other comprehensive loss associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings		(94	)(1)		(56	)		(172	)(1)		(61	)
Other, net of tax		(76	)(2)		70	(3)		3			86	(3)
Other comprehensive income (loss)		(170	)		14			(169	)		25
Comprehensive income including noncontrolling interests		226			593			1,050			2,547
Noncontrolling interests		4			4			12			12
Total comprehensive income attributable to Dominion	$	222		$	589		$	1,038		$	2,535

(1) Primarily reflects unfavorable changes in fair value due to a decrease in interest rates.

(2) Primarily reflects a net decrease in unrealized gains on investments held in nuclear decommissioning trusts.

(3) Primarily reflects a net increase in unrealized gains on investments held in nuclear decommissioning trusts.

PAGE 17

The following table presents Virginia Power’s total comprehensive income:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Net income	$	297		$	380		$	816		$	742
Other comprehensive income (loss):
Net other comprehensive loss associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings		(3	)		(1	)		(4	)		(9	)
Other, net of tax		(8	)		6			(5	)		2
Other comprehensive income (loss)		(11	)		5			(9	)		(7	)
Total comprehensive income	$	286		$	385		$	807		$	735

PAGE 18

Note 9. Fair Value Measurements

Dominion’s and Virginia Power’s fair value measurements are made in accordance with the policies discussed in Note 7 to the Consolidated Financial Statements in their Annual Report on Form 10-K for the year ended December 31, 2010. See Note 10 in this report for further information about their derivatives and hedge accounting activities.

At September 30, 2011, Dominion’s and Virginia Power’s net balance of commodity derivatives categorized as Level 3 fair value measurements was a net liability of $42 million and $21 million, respectively. A hypothetical 10% increase in commodity prices would increase Dominion’s and Virginia Power’s Level 3 net liability by $100 million and $7 million, respectively, while a hypothetical 10% decrease in commodity prices would decrease Dominion’s and Virginia Power’s Level 3 net liability by $101 million and $7 million, respectively.

Non-recurring Fair Value Measurements

In September 2010, Virginia Power evaluated its SO₂ emissions allowances not expected to be consumed by its generating units for potential impairment due to the significant decline in market prices since the July 2010 release of the EPA’s proposed replacement rule for CAIR, ultimately known as CSAPR. As a result of this evaluation, Virginia Power recorded an impairment charge of $13 million ($8 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down its SO₂ emissions allowances not expected to be consumed to their estimated fair value of less than $1 million. In the third quarter of 2011, Dominion and Virginia Power evaluated their SO₂ emissions allowances not expected to be consumed by generating units for potential impairment due to the EPA’s issuance of CSAPR as discussed in Note 15. Prior to the issuance of CSAPR, Dominion and Virginia Power held $57 million and $43 million, respectively, of SO₂ emissions allowances obtained for ARP and CAIR compliance. Due to CSAPR’s establishment of a new allowance program and the elimination of CAIR, Dominion and Virginia Power have more SO₂ emissions allowances than needed for ARP compliance. As a result of this evaluation, Dominion and Virginia Power recorded an impairment charge of $57 million ($34 million after-tax) and $43 million ($26 million after-tax), respectively, in other operations and maintenance expense in their Consolidated Statements of Income, to write down these emissions allowances to their estimated fair value of less than $1 million. To estimate the value of these emissions allowances in both impairment tests, Dominion utilized a market approach by obtaining broker quotes to validate CSAPR’s impact on emissions allowance prices. However, due to limited market activity for future SO₂ vintage year allowances, these are considered a Level 3 fair value measurement.

In June 2010, Dominion evaluated State Line for impairment due to the station’s relatively low level of profitability combined with the EPA’s issuance of a new stringent 1-hour primary NAAQS for SO₂ that would likely require significant environmental capital expenditures in the future. As a result of this evaluation, Dominion recorded an impairment charge of $163 million ($95 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of $59 million. During March 2011, Dominion determined that it was unlikely that State Line would participate in the May 2011 PJM capacity base residual auction that would commit State Line’s capacity from June 2014 through May 2015. This determination reflected an expectation that margins for coal-fired generation will remain compressed in the 2014 and 2015 period in combination with the expectation that State Line may be impacted during the same time period by environmental regulations that would likely require significant capital expenditures. As a result, Dominion evaluated State Line for impairment since it was more likely than not that State Line would be retired before the end of its previously estimated useful life. As a result of this evaluation, Dominion recorded an impairment charge of $55 million ($39 million after-tax) reflected in other operations and maintenance expense in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of less than $1 million. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of State Line’s long-lived assets in both impairment tests. These were considered Level 3 fair value measurements due to the use of significant unobservable inputs including estimates of future power and other commodity prices.

PAGE 19

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, 2011
Assets
Derivatives:
Commodity	$	34	$	623	$	107	$	764
Interest rate		—		103		—		103
Investments(1):
Equity securities:
U.S.:
Large cap		1,551		—		—		1,551
Other		45		—		—		45
Non-U.S.:
Large cap		11		—		—		11
Fixed Income:
Corporate debt instruments		—		310		—		310
U.S. Treasury securities and agency debentures		309		175		—		484
State and municipal		—		296		—		296
Other		—		29		—		29
Cash equivalents and other		1		69		—		70
Restricted cash equivalents		—		204		—		204
Total assets	$	1,951	$	1,809	$	107	$	3,867
Liabilities
Derivatives:
Commodity	$	7	$	728	$	149	$	884
Interest Rate		—		236		—		236
Total liabilities	$	7	$	964	$	149	$	1,120
At December 31, 2010
Assets
Derivatives:
Commodity	$	62	$	734	$	47	$	843
Interest rate		—		54		—		54
Investments(1):
Equity securities:
U.S.:
Large cap		1,709		—		—		1,709
Other		56		—		—		56
Non-U.S.:
Large cap		12		—		—		12
Fixed Income:
Corporate debt instruments		—		327		—		327
U.S. Treasury securities and agency debentures		228		165		—		393
State and municipal		—		286		—		286
Other		—		19		—		19
Cash equivalents and other		25		97		—		122
Restricted cash equivalents		—		400		—		400
Total assets	$	2,092	$	2,082	$	47	$	4,221
Liabilities
Derivatives:
Commodity	$	12	$	716	$	97	$	825
Interest rate		—		5		—		5
Total liabilities	$	12	$	721	$	97	$	830

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

PAGE 20

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,
	2011			2010			2011			2010
(millions)
Beginning balance	$	(122	)	$	32		$	(50	)	$	(66	)
Total realized and unrealized gains (losses):
Included in earnings		(16	)		27			(24	)		40
Included in other comprehensive income (loss)		75			(65	)		16			20
Included in regulatory assets/liabilities		(3	)		(13	)		(35	)		1
Settlements		24			(23	)		47			(41	)
Transfers out of Level 3		—			25			4			29
Ending balance	$	(42	)	$	(17	)	$	(42	)	$	(17	)
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	$	7		$	4		$	29		$	(3	)

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

	Operating revenue			Electric fuel and  other energy-related purchases			Purchased gas			Total
(millions)
Three Months Ended September 30, 2011
Total gains (losses) included in earnings	$	(8	)	$	(8	)	$	—		$	(16	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		7			—			—			7
Three Months Ended September 30, 2010
Total gains (losses) included in earnings	$	5		$	22		$	—		$	27
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		4			—			—			4
Nine Months Ended September 30, 2011
Total gains (losses) included in earnings	$	(8	)	$	(16	)	$	—		$	(24	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		29			—			—			29
Nine Months Ended September 30, 2010
Total gains (losses) included in earnings	$	(5	)	$	49		$	(4	)	$	40
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		(3	)		—			—			(3	)

PAGE 21

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, 2011
Assets
Derivatives:
Commodity	$	—	$	1	$	2	$	3
Investments(1):
Equity securities:
U.S.:
Large cap		613		—		—		613
Other		20		—		—		20
Fixed income:
Corporate debt instruments		—		189		—		189
U.S. Treasury securities and agency debentures		146		50		—		196
State and municipal		—		100		—		100
Other		—		22		—		22
Cash equivalents and other		—		47		—		47
Restricted cash equivalents		—		38		—		38
Total assets	$	779	$	447	$	2	$	1,228
Liabilities
Derivatives:
Commodity	$	—	$	6	$	23	$	29
Interest Rate		—		82		—		82
Total liabilities	$	—	$	88	$	23	$	111
At December 31, 2010
Assets
Derivatives:
Commodity	$	—	$	12	$	15	$	27
Investments(1):
Equity securities:
U.S.:
Large cap		676		—		—		676
Other		25		—		—		25
Fixed Income:
Corporate debt instruments		—		215		—		215
U.S. Treasury securities and agency debentures		80		63		—		143
State and municipal		—		102		—		102
Other		—		15		—		15
Cash equivalents and other		10		61		—		71
Restricted cash equivalents		—		169		—		169
Total assets	$	791	$	637	$	15	$	1,443
Liabilities
Derivatives:
Commodity	$	—	$	5	$	1	$	6
Total liabilities	$	—	$	5	$	1	$	6

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

PAGE 22

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,
	2011			2010			2011			2010
(millions)
Beginning balance	$	(18	)	$	5		$	14		$	(10	)
Total realized and unrealized gains (losses):
Included in earnings		(8	)		22			(16	)		48
Included in regulatory assets/liabilities		(3	)		(13	)		(35	)		2
Settlements		8			(22	)		16			(48	)
Ending balance	$	(21	)	$	(8	)	$	(21	)	$	(8	)

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, 2011 and 2010. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and nine months ended September 30, 2011 and 2010.

Fair Value of Financial Instruments

Substantially all of Dominion’s and Virginia Power’s financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, customer and other receivables, short-term debt and accounts payable are representative of fair value because of the short-term nature of these instruments. For Dominion’s and Virginia Power’s financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

	September 30, 2011				December 31, 2010
	Carrying Amount		Estimated  Fair Value(1)		Carrying Amount		Estimated  Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	16,745	$	19,381	$	14,520	$	16,112
Junior subordinated notes payable to affiliates		268		275		268		261
Enhanced junior subordinated notes		1,467		1,539		1,467		1,560
Subsidiary preferred stock(3)		257		262		257		249
Virginia Power
Long-term debt, including securities due within one year(2)	$	6,868	$	8,233	$	6,717	$	7,489
Preferred stock(3)		257		262		257		249

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

(2) Includes amounts which represent the unamortized discount and premium. At September 30, 2011 and December 31, 2010, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt of approximately $103 million and $49 million, respectively.

(3) Includes issuance expenses of $2 million at September 30, 2011 and December 31, 2010.

Note 10. 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, 2010. See Note 9 in this report for further information about fair value measurements and associated valuation methods for derivatives.

PAGE 23

Dominion

The following table presents the volume of Dominion’s derivative activity as of September 30, 2011. 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 deals, 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)		257		67
Basis		891		405
Electricity (MWh):
Fixed price(1)		20,137,147		23,255,392
FTRs		78,993,580		779,328
Capacity (MW)		155,416		289,585
Liquids (gallons)(2)		138,516,000		281,064,000
Interest rate	$	1,600,000,000	$	2,690,000,000

(1) Includes options.

(2) Includes NGLs and oil.

For the three and nine months ended September 30, 2011 and 2010, gains or losses on hedging instruments determined to be ineffective were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices and were not material for the three and nine months ended September 30, 2011 and 2010.

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, 2011:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next  12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(19	)	$	(7	)		39 months
Electricity		38			21			51 months
NGLs		(39	)		(24	)		39 months
Other		6			1			44 months
Interest rate		(107	)		(5	)		375 months
Total	$	(121	)	$	(14	)

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.

The sale of the majority of Dominion’s remaining E&P operations during 2010 resulted in the discontinuance of hedge accounting for certain cash flow hedges, as discussed in Note 3.

In addition, changes to Dominion’s financing needs during the first and second quarters of 2010 resulted in the discontinuance of hedge accounting for certain cash flow hedges, since it became probable that forecasted interest payments would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a benefit recorded to interest and related charges reflecting the reclassification of gains from AOCI to earnings of $110 million ($67 million after-tax) in the nine months ended September 30, 2010. The reclassification of gains from AOCI to earnings was partially offset by subsequent changes in fair value of $37 million ($23 million after-tax) for the nine months ended September 30, 2010.

PAGE 24

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, 2011
ASSETS
Current Assets
Commodity	$	150	$	412	$	562
Interest rate		36		—		36
Total current derivative assets		186		412		598
Noncurrent Assets
Commodity		105		97		202
Interest rate		67		—		67
Total noncurrent derivative assets(1)		172		97		269
Total derivative assets	$	358	$	509	$	867
LIABILITIES
Current Liabilities
Commodity	$	186	$	476	$	662
Interest rate		124		7		131
Total current derivative liabilities(2)		310		483		793
Noncurrent Liabilities
Commodity		119		103		222
Interest rate		74		31		105
Total noncurrent derivative liabilities(3)		193		134		327
Total derivative liabilities	$	503	$	617	$	1,120
December 31, 2010
ASSETS
Current Assets
Commodity	$	291	$	425	$	716
Interest rate		23		—		23
Total current derivative assets		314		425		739
Noncurrent Assets
Commodity		44		83		127
Interest rate		31		—		31
Total noncurrent derivative assets(1)		75		83		158
Total derivative assets	$	389	$	508	$	897
LIABILITIES
Current Liabilities
Commodity	$	178	$	455	$	633
Total current derivative liabilities(2)		178		455		633
Noncurrent Liabilities
Commodity		86		106		192
Interest rate		5		—		5
Total noncurrent derivative liabilities(3)		91		106		197
Total derivative liabilities	$	269	$	561	$	830

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

(2) Current derivative liabilities are presented in other current liabilities in Dominion’s Consolidated Balance Sheets.

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

PAGE 25

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, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	28
Purchased gas					(7	)
Electric fuel and other energy-related purchases					2
Total commodity	$	69			23		$	(1	)
Interest rate(3)		(204	)		(8	)		(76	)
Total	$	(135	)	$	15		$	(77	)
Three Months Ended September 30, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	88
Purchased gas					(6	)
Electric fuel and other energy-related purchases					4
Purchased electric capacity					1
Total commodity	$	(5	)		87		$	(6	)
Interest rate(3)		—			—			1
Foreign currency(4)		—			—			—
Total	$	(5	)	$	87		$	(5	)
Nine Months Ended September 30, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	88
Purchased gas					(61	)
Electric fuel and other energy-related purchases					4
Purchased electric capacity					1
Total commodity	$	(24	)		32		$	(10	)
Interest rate(3)		(236	)		(8	)		(76	)
Total	$	(260	)	$	24		$	(86	)
Nine Months Ended September 30, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	383
Purchased gas					(122	)
Electric fuel and other energy-related purchases					(4	)
Purchased electric capacity					3
Total commodity	$	277			260		$	(17	)
Interest rate(3)		(3	)		109			(23	)
Foreign currency(4)		—			1			(2	)
Total	$	274		$	370		$	(42	)

PAGE 26

(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.

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

	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	2011			2010			2011			2010
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	15		$	45		$	56		$	71
Purchased gas		(10	)		(13	)		(28	)		(42	)
Electric fuel and other energy-related purchases		(8	)		23			(16	)		48
Interest rate(2)		(4	)		—			(4	)		(37	)
Total	$	(7	)	$	55		$	8		$	40

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

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

Virginia Power

The following table presents the volume of Virginia Power’s derivative activity as of September 30, 2011. 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 deals, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price		8		—
Basis		4		—
Electricity (MWh):
Fixed price		614,400		—
FTRs		78,565,145		779,328
Capacity (MW)		122,000		182,500
Interest rate	$	800,000,000	$	490,000,000

For the three and nine months ended September 30, 2011 and 2010, gains or losses on hedging instruments determined to be ineffective were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices and were not material for the three and nine months ended September 30, 2011 and 2010.

Gains (losses) on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at September 30, 2011 were not material.

PAGE 27

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, 2011
ASSETS
Current Assets
Commodity	$	1	$	2	$	3
Total current derivative assets(1)		1		2		3
Total derivative assets	$	1	$	2	$	3
LIABILITIES
Current Liabilities
Commodity	$	3	$	24	$	27
Interest rate		34		7		41
Total current derivative liabilities(2)		37		31		68
Noncurrent Liabilities
Commodity		2		—		2
Interest rate		10		31		41
Total noncurrent derivative liabilities(3)		12		31		43
Total derivative liabilities	$	49	$	62	$	111
December 31, 2010
ASSETS
Current Assets
Commodity	$	12	$	15	$	27
Total current derivative assets(1)		12		15		27
Total derivative assets	$	12	$	15	$	27
LIABILITIES
Current Liabilities
Commodity	$	2	$	1	$	3
Total current derivative liabilities(2)		2		1		3
Noncurrent Liabilities
Commodity		3		—		3
Total noncurrent derivative liabilities(3)		3		—		3
Total derivative liabilities	$	5	$	1	$	6

(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 28

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, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Total commodity	$	(1	)		(1	)	$	(1	)
Interest rate(3)		(5	)		—			(76	)
Total	$	(6	)	$	(1	)	$	(77	)
Three Months Ended September 30, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Purchased electric capacity				$	1
Total commodity	$	(1	)		1		$	(6	)
Interest rate(3)		—			—			1
Total	$	(1	)	$	1		$	(5	)
Nine Months Ended September 30, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Purchased electric capacity				$	1
Total commodity	$	(1	)		1		$	(10	)
Interest rate(3)		(5	)		1			(76	)
Total	$	(6	)	$	2		$	(86	)
Nine Months Ended September 30, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Purchased electric capacity					3
Total commodity	$	(2	)		2		$	(17	)
Interest rate(3)		(1	)		9			(23	)
Foreign currency(4)		—			—			(2	)
Total	$	(3	)	$	11		$	(42	)

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

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

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

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

PAGE 29

	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
	Three Months  Ended September 30,					Nine Months  Ended September 30,
Derivatives not designated as hedging instruments	2011			2010		2011			2010
(millions)
Derivative Type and Location of Gains (Losses)
Commodity(2)	$	(8	)	$	22	$	(16	)	$	49
Interest rate(3)		(4	)		—		(4	)		(3	)
Total	$	(12	)	$	22	$	(20	)	$	46

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

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

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

Note 11. 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 $89 million and $93 million at September 30, 2011 and December 31, 2010, respectively. Net unrealized losses on trading securities totaled $5 million and $1 million for the three and nine months ended September 30, 2011, respectively. Net unrealized losses on trading securities totaled $1 million for the nine months ended September 30, 2010. Cost-method investments held in Dominion’s rabbi trusts totaled $17 million and $18 million at September 30, 2011 and December 31, 2010, respectively.

PAGE 30

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, 2011
Marketable equity securities
U.S.:
Large Cap	$	1,147	$	377	$	—		$	1,524
Other		36		4		—			40
Marketable debt securities:
Corporate bonds		294		18		(2	)		310
U.S. Treasury securities and agency debentures		460		24		(1	)		483
State and municipal		237		18		—			255
Other		29		1		(1	)		29
Cost method investments		113		—		—			113
Cash equivalents and other(2)		45		—		—			45
Total	$	2,361	$	442	$	(4	)(3)	$	2,799
December 31, 2010
Marketable equity securities:
U.S.:
Large Cap	$	1,161	$	515	$	—		$	1,676
Other		39		11		—			50
Marketable debt securities:
Corporate bonds		310		18		(1	)		327
U.S. Treasury securities and agency debentures		380		12		(1	)		391
State and municipal		244		7		(4	)		247
Other		19		—		—			19
Cost method investments		108		—		—			108
Cash equivalents and other(2)		79		—		—			79
Total	$	2,340	$	563	$	(6	)(3)	$	2,897

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

(2) Includes pending purchases of securities of $23 million and $43 million at September 30, 2011 and December 31, 2010, respectively.

(3) The fair value of securities in an unrealized loss position was $158 million and $252 million at September 30, 2011 and December 31, 2010, respectively.

PAGE 31

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2011 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	93
Due after one year through five years		304
Due after five years through ten years		316
Due after ten years		364
Total	$	1,077

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,
	2011		2010		2011		2010
(millions)
Proceeds from sales	$	465	$	398	$	1,404	$	1,538
Realized gains(1)		23		16		55		89
Realized losses(1)		62		4		82		58

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	54		$	4		$	69		$	52
Losses recorded to decommissioning trust regulatory liability		(16	)		(1	)		(22	)		(17	)
Losses recognized in other comprehensive income (before taxes)		(2	)		—			(3	)		(2	)
Net impairment losses recognized in earnings	$	36		$	3		$	44		$	33

(1) Amount includes other-than-temporary impairment losses for debt securities of $3 million and $1 million for the three months ended September 30, 2011 and 2010, respectively, and $5 million and $4 million for the nine months ended September 30, 2011 and 2010, respectively.

PAGE 32

Virginia Power

Decommissioning Trust Securities

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

	Amortized Cost		Total Unrealized Gains(1)		Total Unrealized Losses(1)			Fair Value
(millions)
September 30, 2011
Marketable equity securities:
U.S.:
Large Cap	$	459	$	154	$	—		$	613
Other		18		2		—			20
Marketable debt securities:
Corporate bonds		180		10		(1	)		189
U.S. Treasury securities and agency debentures		189		7		—			196
State and municipal		93		7		—			100
Other		22		1		(1	)		22
Cost method investments		113		—		—			113
Cash equivalents and other(2)		32		—		—			32
Total	$	1,106	$	181	$	(2	)(3)	$	1,285
December 31, 2010
Marketable equity securities
U.S.:
Large Cap	$	469	$	207	$	—		$	676
Other		20		5		—			25
Marketable debt securities:
Corporate bonds		205		10		—			215
U.S. Treasury securities and agency debentures		141		2		—			143
State and municipal		103		1		(2	)		102
Other		15		—		—			15
Cost method investments		108		—		—			108
Cash equivalents and other(2)		35		—		—			35
Total	$	1,096	$	225	$	(2	)(3)	$	1,319

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

(2) Includes pending purchases of securities of $14 million and $35 million at September 30, 2011 and December 31, 2010, respectively.

(3) The fair value of securities in an unrealized loss position was $101 million and $159 million at September 30, 2011 and December 31, 2010, respectively.

The fair value of Virginia Power’s debt securities at September 30, 2011, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	11
Due after one year through five years		164
Due after five years through ten years		199
Due after ten years		133
Total	$	507

PAGE 33

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions)
Proceeds from sales	$	242	$	248	$	838	$	959
Realized gains(1)		10		6		21		43
Realized losses(1)		22		1		30		21

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	19		$	2		$	26		$	21
Losses recorded to decommissioning trust regulatory liability		(16	)		(1	)		(22	)		(17	)
Net impairment losses recognized in earnings	$	3		$	1		$	4		$	4

(1) Amount includes other-than-temporary impairment losses for debt securities of $2 million and $1 million for the three months ended September 30, 2011 and 2010, respectively, and $4 million and $2 million for the nine months ended September 30, 2011 and 2010, respectively.

Note 12. Regulatory Matters

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 14 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010 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, 2011 and June 30, 2011.

Virginia Regulation

Biennial Review

In connection with its current biennial review of Virginia Power’s base rates, terms and conditions, the Virginia Commission will determine whether Virginia Power’s earnings for the 2009 and 2010 test years, considered as a whole, were within 50 basis points of the authorized ROE of 11.9% established in the Virginia Settlement Approval Order. The Virginia Commission will also authorize an ROE for Virginia Power that will be applied to Riders R, S, C1 and C2, as well as Riders W and B if approved, and that will be used to measure base rate earnings prospectively. In September 2011, the Virginia Commission conducted an evidentiary hearing related to the biennial review. In its testimony presented as part of the proceeding, the Virginia Commission staff proposed making several regulatory accounting and other adjustments to Virginia Power’s earnings. If the Virginia Commission were to accept all of these proposed adjustments, Virginia Power would have earned an ROE of 14.11% during the 2009 and 2010 test years, resulting in a total credit to customers of approximately $143 million. Virginia Power believes that the adjustments proposed by the Virginia Commission staff were improper and inconsistent with prior Virginia Power regulatory precedent and the terms of the 2010 Virginia Settlement Approval Order. Due to the uncertainty surrounding the Virginia Commission’s final ruling and since Virginia Power believes it earned an ROE of 12.1%, which is within the allowed range, during the 2009 and 2010 test years, Virginia Power has not recognized a liability related to the staff’s recommendation as of September 30, 2011.

Virginia Power is requesting authorization of a prospective ROE of 12.5%, inclusive of a performance incentive of 100 basis points as provided for by the Regulation Act. In its filed and direct testimony presented as part of the evidentiary hearing, the Virginia Commission staff recommended a prospective ROE of 10.67%, inclusive of an RPS performance incentive of 50 basis points. The staff’s recommended ROE is equal to the minimum ROE permitted by the staff’s interpretation of the Regulation Act. Pursuant to the Regulation Act, Virginia Power’s authorized ROE, exclusive of any performance or other statutory incentive, can be no lower than the average of the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., with certain limitations as described in the Regulation Act.

A final order in the 2011 biennial review for base rates must be issued no later than November 30, 2011.

PAGE 34

DSM Riders C1 and C2

In September 2011, Virginia Power filed with the Virginia Commission an application for approval of six new energy efficiency DSM programs. Virginia Power also filed an annual update to Riders C1 and C2, with a proposed revenue requirement of approximately $86 million for the period May 1, 2012 through April 30, 2013. This revenue requirement includes the new DSM programs, five previously-approved DSM programs, and a previously-approved electric vehicle pilot program. The proposed revenue requirement represents an approximately $68 million increase over the revenue requirement approved in the 2010 Riders C1 and C2 proceeding and includes approximately $26 million to recover projected lost revenues associated with energy efficiency programs. The filing utilizes a 12.5% placeholder ROE pending the Virginia Commission’s determination in the 2011 biennial review.

Mt. Storm-to-Doubs Line

In September 2011, the Virginia Commission approved Virginia Power’s application to rebuild its portion of the Mt. Storm-to-Doubs line. Subject to applicable state and federal regulatory approvals, Virginia Power’s portion of the rebuild project is expected to cost approximately $350 million and is expected to be completed by June 2015.

North Anna COL

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna, which Virginia Power owns along with ODEC. In February 2011, ODEC informed Virginia Power of its intent to no longer participate in the development of a potential new unit at North Anna. Virginia Power and ODEC are currently working together to finalize the terms and conditions of such withdrawal.

Virginia Power has not yet committed to building a new nuclear unit at North Anna. If Virginia Power decides to build the 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 continues to pursue the COL from the NRC. The current NRC schedule for issuance of the COL is 2013.

The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the ASLB of the NRC permitted BREDL to intervene in the proceeding. All of BREDL’s previous contentions in this proceeding have been dismissed. In September 2011, BREDL submitted a new proposed contention seeking to litigate issues related to the August 2011 Mineral, Virginia earthquake. In October 2011, the ASLB granted a motion filed by Virginia Power, BREDL and the NRC staff to hold any ruling on this proposed contention in abeyance until Virginia Power completes an assessment of this earthquake. No other persons have sought to intervene in the proceeding. If a new contention is not admitted, the mandatory NRC hearing will be uncontested with respect to other issues.

On April 14, 2011, twenty-one organizations and individuals that had previously intervened opposing various reactor licensing proceedings filed a petition requesting that the NRC suspend all decisions regarding reactor licensing and design certification pending completion of an NRC task force review of the events at Fukushima, Japan, among other requested relief. The North Anna 3 COL proceeding is one of the pending proceedings identified in this petition, and BREDL served the petition in the North Anna 3 COL proceeding on April 18, 2011. In September 2011, the NRC denied the petitioners’ requests to suspend licensing and design certification proceedings. The only relief granted was the petitioners’ request that the NRC perform a safety analysis of the regulatory implications of the Fukushima event to the extent it is doing so.

North Carolina Regulation

In August 2011, Virginia Power filed its annual fuel expense recovery application with the North Carolina Commission. The application requests a revenue increase of approximately $37 million, including approximately $14 million of previously deferred fuel costs. If approved, revised fuel rates would go into effect January 1, 2012.

FERC Gas Regulation

Ellisburg-to-Craigs Project

In September 2011, FERC approved DTI’s proposed Ellisburg-to-Craigs project. The project is expected to have capacity of approximately 150,000 dekatherms per day, which will be leased by TGP to move Marcellus shale natural gas supplies from TGP’s 300 Line pipeline system in northern Pennsylvania to its 200 Line pipeline system in upstate New York. The project is expected to cost approximately $46 million. Subject to receipt of FERC approval to commence construction, construction of additional compression facilities and a new measurement and regulating station is expected to begin in March 2012, with a projected in-service date of November 2012.

PAGE 35

Northeast Expansion Project

In August 2011, DTI received FERC authorization for the Northeast Expansion Project. The project is expected to provide approximately 200,000 dekatherms per day of firm transportation services for CONSOL’s Marcellus Shale natural gas production from various receipt points in central and southwestern Pennsylvania to a nexus of market pipelines and storage facilities in Leidy, Pennsylvania. The project is expected to cost approximately $100 million. Subject to receipt of FERC approval to commence construction, construction of new compression facilities at three existing compressor stations in central Pennsylvania is expected to begin in March 2012, with a projected in-service date of November 2012.

Ohio Regulation

In March 2011, East Ohio filed a request with the Ohio Commission to accelerate the PIR program. In August 2011, the Ohio Commission approved the stipulation filed in East Ohio’s accelerated PIR proceeding. The stipulation provides for an increase in annual PIR capital investment from the current level of approximately $120 million stepping up to approximately $160 million by 2013. In addition, the stipulation provides for cost recovery over a five-year period commencing upon the approval of the Ohio Commission. In accordance with the stipulation, East Ohio requested the dismissal of its appeal at the Ohio Supreme Court regarding its opposition to the Ohio Commission’s order concerning East Ohio’s first year PIR cost recovery charge.

In August 2011, East Ohio submitted its annual application to adjust the cost recovery charge under the previously approved PIR program. A supplement to the application was filed in September 2011. The proposed recovery charge includes actual costs and a return related to investments made through June 30, 2011. A settlement agreement filed with the Ohio Commission in October 2011 supports the revenue requirement of $37 million reflected in the application.

Note 13. Variable Interest Entities

As discussed in Note 16 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010, 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 $1.4 billion as of September 30, 2011. Virginia Power paid $52 million and $53 million for electric capacity and $38 million and $46 million for electric energy to these entities in the three months ended September 30, 2011 and 2010, respectively. Virginia Power paid $156 million and $160 million for electric capacity and $103 million and $120 million for electric energy to these entities in the nine months ended September 30, 2011 and 2010, respectively.

Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $100 million and $104 million for the three months ended September 30, 2011 and 2010, respectively, and $292 million and $352 million for the nine months ended September 30, 2011 and 2010, 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.

As discussed in Note 23 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010, Dominion leases the Fairless generating facility in Pennsylvania, which began commercial operations in June 2004. The lease expires in 2013 and, at that time, Dominion may renew the lease on terms mutually agreeable to Dominion and the lessor, Juniper, based on original project costs and current market conditions; purchase Fairless at its original construction cost ($898 million) plus 51% of any appraised value in excess of original construction cost; or sell Fairless, on behalf of Juniper, to an independent third party. As an operating lease, the asset and related borrowings used to finance the construction of the asset are not included in the Consolidated Balance Sheets as of September 30, 2011 or December 31, 2010.

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 has no voting equity interest in Juniper. Because Juniper had been deemed a business, Dominion was not required to evaluate whether Juniper was a VIE.

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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 it’s sole remaining asset, Juniper no longer qualified as a business as of October 2011, which required that Dominion determine whether Juniper is a VIE. Dominion concluded Juniper is a VIE because the entity’s capitalization is insufficient to support its operations, the power to direct the most significant activities of the entity are not performed by the equity holders, and Dominion, through its residual value guarantee as disclosed in Note 15 of this report, guarantees a portion of the residual value of Fairless. The activities that most significantly impact Juniper’s economic performance relate to the operation of Fairless. These decisions are made by Dominion and as such, Dominion is considered the primary beneficiary.

Accordingly, Dominion will consolidate Juniper in the fourth quarter of 2011 and expects to record, at fair value, approximately $1 billion of property, plant and equipment, $900 million of debt and $100 million of noncontrolling interests. The debt is non-recourse to Dominion and is secured by Juniper’s assets. Dominion has not provided any financial or other support to Juniper in the current period that it was not previously contractually required to provide.

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, 2011, Dominion’s commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:

	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility(1)	$	3,000	$	783	$	—	$	2,217
Joint revolving credit facility(2)		500		—		127		373
Total	$	3,500	$	783	$	127	$	2,590

(1) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. 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) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

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

At September 30, 2011, Virginia Power’s share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion were as follows:

	Facility Sub-limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility(1)	$	1,000	$	550	$	—	$	450
Joint revolving credit facility(2)		250		—		56		194
Total	$	1,250	$	550	$	56	$	644

(1) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. 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 applicable sub-limit under this credit facility can be increased or decreased multiple times per year.

(2) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s applicable sub-limit under this credit facility can be increased or decreased multiple times per year.

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In addition to the credit facility commitments disclosed above, Virginia Power also has a $120 million credit facility that was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This facility supports certain tax-exempt financings of Virginia Power.

Long-term Debt

In August 2011, Dominion issued $500 million of 4.9% senior notes that mature in 2041 and $450 million of 1.95% senior notes that mature in 2016. The proceeds were used for general corporate purposes including the repayment of short-term debt.

In December 2010, Brayton Point borrowed $160 million and $75 million in connection with the Massachusetts Development Finance Agency Recovery Zone Facility Bonds, Series 2010 A and the Solid Waste Disposal Revenue Bonds, Series 2010 B, respectively, which mature in 2041. The proceeds are being used to finance certain qualifying facilities at Brayton Point. Due to unfavorable market conditions, Dominion acquired the bonds upon issuance in December 2010 with the intention of remarketing them to third parties at a later time. At December 31, 2010, these bonds had not been remarketed and thus were not reflected on the Consolidated Balance Sheets. In July 2011, the Series 2010 B bonds were remarketed to a third party using a remarketing process, and bear interest at a variable rate for the first five years, after which they will bear interest at a market rate to be determined at that time. In August 2011, the Series 2010 A bonds were remarketed to third parties using a remarketing process, and bear interest at a coupon rate of 2.25% for the first five years, after which they will bear interest at a market rate to be determined at that time.

In March 2011, Dominion issued $500 million of 4.45% senior notes that mature in 2021 and $400 million of 1.80% senior notes that mature in 2014. The proceeds were used for general corporate purposes including the repayment of short-term debt.

In December 2010 and September 2009, Virginia Power borrowed $100 million and $60 million, respectively, in connection with the $160 million Industrial Development Authority of Wise County Solid Waste and Sewage Disposal Revenue Bonds, Series 2009 A, which mature in 2040. The proceeds are being used to finance certain qualifying facilities at the Virginia City Hybrid Energy Center. Due to unfavorable market conditions, Virginia Power acquired the bonds upon issuance with the intention of remarketing them to third parties at a later time. At December 31, 2010, these bonds had not been remarketed and thus were not reflected on the Consolidated Balance Sheets. In March 2011, the bonds were remarketed to a third party and bear interest at a variable rate for the first five years, after which they will bear interest at a market rate to be determined at that time.

Convertible Securities

At September 30, 2011, Dominion had $165 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, 2011, the conversion rate has been adjusted, primarily due to individual dividend payments above the level paid at issuance, to 28.8178 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $34.70.

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, 2011 approximately $37 million of the contingent convertible senior notes were converted by holders. The senior notes are eligible for conversion during the fourth quarter of 2011.

Issuance of Common Stock

Dominion maintains Dominion Direct^® and a number of employee savings plans through which employer and employee contributions may be invested in the Company’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans by employees, Dominion Direct^® participants and the Company.

Since February 2010, Dominion Direct^® and the Dominion employee savings plans have been purchasing Dominion common stock on the open market with the proceeds received through these programs, rather than having additional new common shares issued.

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During the nine months ended September 30, 2011, Dominion issued approximately 1 million shares of common stock and received cash proceeds of $37 million through the exercise of employee stock options.

Repurchase of Common Stock

In the first quarter of 2011, Dominion announced that it expected to repurchase between $600 million and $700 million of common stock with cash tax savings resulting from the extension of the bonus depreciation allowance discussed in Note 6 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010. During the nine months ended September 30, 2011, Dominion repurchased approximately 13 million shares of common stock for approximately $601 million on the open market under this program, at an average price of $46.37 per share. In October 2011, Dominion determined that it does not plan to repurchase additional shares under this program.

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, 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. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss does 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

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.

Air

In July 2011, the EPA issued a final replacement rule for CAIR, called CSAPR, that requires 27 states to reduce power plant emissions that cross state lines. CSAPR establishes new SO₂ and NO_x emissions cap and trade programs that are completely independent of the current ARP. Specifically, CSAPR requires 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.

Prior to the issuance of CSAPR, Dominion and Virginia Power held $57 million and $43 million, respectively, of SO₂ emissions allowances obtained for ARP and CAIR compliance. Due to CSAPR’s establishment of a new allowance program and the elimination of CAIR, Dominion and Virginia Power have more SO₂ emissions allowances than needed for ARP compliance, which resulted in the impairment of these allowances in the third quarter of 2011. See Note 9 for further details of the impairments.

With respect to Dominion’s generation fleet, the impact of the rule is not expected to be material. However, a large number of petitions for review of CSAPR have been filed in federal court and it is anticipated that there will be significant litigation of this rule. In addition, the EPA has proposed, but not yet finalized, changes to the rule. Accordingly, future outcomes of litigation and/or final action to modify the rule could affect this assessment.

The CAA 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.

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

Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The CAA authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. In addition to any such penalties that may be awarded, an adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time. Such expenditures could affect future results of operations, cash flows, and financial condition. Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.

In June 2010, the Conservation Law Foundation and Healthlink Inc. filed a Complaint in the District Court of Massachusetts against Dominion Energy New England, Inc. alleging that Salem Harbor units 1, 2, 3, and 4 have been and are in violation of visible emissions standards and monitoring requirements of the Massachusetts State Implementation Plan and the station’s state and federal operating permits. Although Dominion cannot predict the outcome of this matter at this time, it is not expected to have a material effect on results of operations, financial condition and/or cash flows.

Water

In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. Currently, Dominion is constructing the cooling towers and estimates the total cost to install these cooling towers at approximately $600 million, with remaining expenditures of approximately $100 million included in its planned capital expenditures through 2012.

In October 2007, the VSWCB issued a renewed VPDES permit for North Anna. BREDL, and other persons, appealed the VSWCB’s decision to the Richmond Circuit Court, challenging several permit provisions related to North Anna’s discharge of cooling water. In February 2009, the court ruled that the VSWCB was required to regulate the thermal discharge from North Anna into the waste heat treatment facility. Virginia Power filed a motion for reconsideration with the court in February 2009, which was denied. The final order was issued by the court in September 2009. The court’s order allows North Anna to continue to operate pursuant to the currently issued VPDES permit. In October 2009, Virginia Power filed a Notice of Appeal of the court’s order with the Richmond Circuit Court, initiating the appeals process to the Virginia Court of Appeals. In June 2010, the Virginia Court of Appeals reversed the Richmond Circuit Court’s September 2009 order. The Virginia Court of Appeals held that the lower court had applied the wrong standard of review, and that the VSWCB’s determination not to regulate the station’s thermal discharge into the waste heat treatment facility was lawful. In July 2010, BREDL and the other original appellants filed a petition for appeal to the Supreme Court of Virginia requesting that it review the Court of Appeals’ decision. In December 2010, the Supreme Court of Virginia granted BREDL’s petition. Briefing on the merits of the case was completed in February 2011. The court has scheduled oral arguments for October 31, 2011. Dominion is currently unable to make an estimate of the potential financial statement impacts related to this matter. However, an adverse resolution could ultimately require significant capital expenditures which could have a material effect on Dominion’s and Virginia Power’s results of operations, financial condition and/or cash flows.

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, however, Dominion cannot currently predict the outcome of this evaluation. 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

In March 2011, the EPA issued a final rule identifying NHSMs that would be considered solid waste when burned in combustion units, as opposed to being legitimate fuels or ingredients. The rule’s premise is that any combusted NHSM is a solid waste unless such material satisfies the rule’s criteria for either a fuel or an ingredient. Sources that combust solid waste are considered

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solid waste incinerators rather than industrial or utility boilers and would have to comply with the EPA’s more stringent emission standards for solid waste incinerators. Dominion and Virginia Power have several electric generating units that combust fuel materials that may be subject to the rule. Some units use a technology that combusts residual coal in fly ash to recover additional energy from unburned carbon. This technology also produces a final ash product that is marketable for beneficial reuse in cement production. Because of the uncertainty associated with the rule’s potential applicability to this and other processes, in June 2011, Dominion filed a petition for review with the Court of Appeals for the District of Columbia Circuit challenging the final rule. In October 2011, the EPA announced that it would initiate additional rulemaking proceedings to revise the final rule. Although Dominion cannot predict the outcome of this matter at this time, it is not expected to have a material effect on results of operations, financial condition, and/or cash flows.

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

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

In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. Virginia Power has until early November 2011 to respond to the EPA regarding its willingness 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 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. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the 17 former sites with which Dominion is associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program and Dominion has not yet estimated the future remediation costs. Due to the uncertainty surrounding these sites, Dominion is unable to make an estimate of the potential financial statement impacts related to these sites.

Climate Change Legislation and Regulation

Massachusetts, Rhode Island and Connecticut, among other states, have joined the 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 2011 and possibly continuing through 2012, RGGI will undergo a program review which could impact regulations and implementation of RGGI. The impact of this program review on Dominion’s fossil fired generation operations in RGGI states is unknown at this time. Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.

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Three of Dominion’s facilities, Brayton Point, Salem Harbor and Manchester Street, are subject to RGGI. Beginning with calendar year 2009, RGGI requires that Dominion cover each ton of CO₂ direct stack emissions from these facilities with either an allowance or an offset. The allowances can be purchased through auction or through a secondary market. Dominion has participated in RGGI allowance auctions to date and has procured allowances to meet its estimated compliance requirements under RGGI for 2009, 2010, 2011 and partially for 2012, therefore Dominion does not expect compliance with RGGI to have a material impact on its results of operations or financial condition. However, during August 2011, a lawsuit was filed in New York seeking to retroactively rescind RGGI participation by that state. Currently, a percentage of Dominion’s RGGI allowances have been acquired from New York. The acquisition cost of these allowances totaled approximately $34 million, of which the majority have been expensed as consumed. If Dominion is unable to tender New York allowances for RGGI compliance or RGGI does not exchange these allowances for other state allowances, replacement allowances would have to be purchased for 2009 through 2011 compliance. Dominion cannot predict the outcome of the case at this time. Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.

In August 2011, the EPA announced a delay in the schedule for proposing regulations which would establish GHG performance standards for new, modified and existing fossil-fired electric generating units. Regulations were expected to be proposed by July 2011 and finalized by May 2012. The schedule for a proposed rulemaking is now delayed beyond October 2011.

Guarantees

Dominion

At September 30, 2011, Dominion had issued $86 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of September 30, 2011, Dominion’s exposure under these guarantees was $54 million, primarily related to certain reserve requirements associated with non-recourse financing.

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

At September 30, 2011, Dominion had issued the following subsidiary guarantees:

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	363	$	363
Commodity transactions(3)		3,182		429
Lease obligation for power generation facility(4)		748		748
Nuclear obligations(5)		231		50
Other(6)		517		141
Total	$	5,041	$	1,731

(1) Represents the estimated portion of the guarantee’s stated limit that is utilized as of September 30, 2011 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount.

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

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

(4) Guarantee of a DEI subsidiary’s leasing obligation for Fairless, including a residual value guarantee.

(5) 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.

(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.

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Spent Nuclear Fuel

Under provisions of the Nuclear Waste Policy Act of 1982, Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Companies’ contracts with the DOE. In January 2004, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims against the DOE requesting damages in connection with its failure to commence accepting spent nuclear fuel. In October 2008, the court issued an opinion and order for Dominion in the amount of approximately $155 million, which includes approximately $112 million in damages incurred by Virginia Power for spent fuel-related costs at Surry and North Anna and approximately $43 million in damages incurred for spent nuclear fuel-related costs at Millstone through June 30, 2006. In December 2008, the government appealed the judgment to the U.S. Court of Appeals for the Federal Circuit. The government’s initial brief in the appeal was filed in June 2010. The issues raised by the government on appeal pertained to the damages awarded to Dominion for Millstone. The government did not take issue with the damages awarded to Virginia Power for Surry or North Anna. As a result, Virginia Power recognized a receivable in the amount of $174 million, largely offset against property, plant and equipment and regulatory assets and liabilities, representing certain spent nuclear fuel-related costs incurred through June 30, 2010.

In the second quarter of 2011, the Federal Appeals Court issued a decision affirming the trial court’s damages award. The government did not seek rehearing of the Federal Appeals Court decision or seek review by the U.S. Supreme Court. As a result, Dominion recognized a receivable in the amount of $64 million for certain Millstone spent nuclear fuel-related costs incurred through June 30, 2011 that are now considered probable of recovery. Dominion recognized a pre-tax benefit of $24 million, with $17 million recorded in other operations and maintenance expense and $7 million recorded in depreciation, depletion and amortization expense for the six months ended June 30, 2011, with the remainder largely offset against property, plant and equipment. Dominion received payment of the $155 million damages award, including $112 million of damages incurred by Virginia Power, during the third quarter of 2011.

The Companies continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. At September 30, 2011, Dominion’s and Virginia Power’s receivables for spent nuclear fuel-related costs totaled $99 million and $75 million, respectively. The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Surety Bonds and Letters of Credit

As of September 30, 2011, Dominion had purchased $151 million of surety bonds, including $62 million at Virginia Power, and authorized the issuance of standby letters of credit by financial institutions of $127 million, including $56 million at Virginia Power, to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of the surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

Merchant Generation Operations

Dominion continually reviews its portfolio of assets to determine which assets fit strategically and support its objectives to improve return on invested capital and shareholder value. If Dominion identifies assets that do not support its objectives and believes they may be of greater value to another owner, Dominion may consider such assets for divestiture. In connection with this effort, in the first quarter of 2011, Dominion decided to pursue the sale of Kewaunee. If these efforts are successful, Dominion may be required to present Kewaunee’s assets and liabilities that are subject to sale as held for sale in its Consolidated Balance Sheet and Kewaunee’s results of operations in discontinued operations in its Consolidated Statements of Income. Held for sale classification would require that amounts be recorded at the lower of book value or sale price less costs to sell and could result in the recording of an impairment charge. Any sale of Kewaunee would be subject to the approval of Dominion’s Board of Directors, as well as applicable state and federal approvals.

During the second quarter of 2011, Dominion announced that State Line would shut down by mid-2014, and that it would cease operating two of the four units at Salem Harbor by the end of 2011 and plans to retire all four units on June 1, 2014. In the second quarter of 2011, Dominion recorded a $17 million ($11 million after-tax) charge in other operations and maintenance expense for severance costs related to the expected closings of these merchant generation facilities. In August 2011, Dominion announced that State Line would shut down in the first quarter of 2012, given a continued decline in power prices and the expected cost to comply with CSAPR. During the third quarter of 2011, Dominion recorded a $15 million ($10 million after-tax) charge in other operations and maintenance expense related to the accelerated closure of State Line.

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PJM Ancillary Service Revenues

In September 2011, PJM identified the need to adjust its calculations of certain ancillary service revenues paid to a number of generators. PJM is currently in the process of performing the required recalculations and Virginia Power has accrued a liability of $35 million, which represents its best estimate of future billing adjustments from PJM related to revenues recognized in 2010 and 2011.

Note 16. Credit Risk

Dominion’s and Virginia Power’s accounting policies for credit risk are discussed in Note 24 to the Consolidated Financial Statements in their Annual Report on Form 10-K for the year ended December 31, 2010.

At September 30, 2011, Dominion’s gross credit exposure totaled $364 million. After the application of collateral, credit exposure is unchanged. Of this amount, investment grade counterparties, including those internally rated, represented 79%. One counterparty exposure represents 10% of Dominion’s total exposure and is a large financial institution rated investment grade.

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, 2011 and December 31, 2010, Dominion would have been required to post an additional $66 million and $88 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion had posted $81 million in collateral, including $53 million of letters of credit, at September 30, 2011 and $54 million in collateral, including $19 million of letters of credit, at December 31, 2010, 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, 2011 and December 31, 2010 was $209 million and $210 million, respectively, which does not include the impact of any offsetting asset positions. See Note 10 for further information about derivative instruments.

Note 17. Related Party Transactions

Virginia Power engages in related-party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power is included in Dominion’s consolidated federal income tax return and participates in certain Dominion benefit plans. A discussion of significant related party transactions follows.

Transactions with Affiliates

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

DRS provides 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,
	2011		2010		2011		2010
(millions)
Commodity purchases from affiliates	$	150	$	150	$	302	$	306
Services provided by affiliates		101		106		294		355

Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. Virginia Power’s outstanding borrowings, net of repayments, under the Dominion money pool for its nonregulated subsidiaries totaled $166 million and $24 million as of September 30, 2011 and December 31, 2010, respectively. Virginia Power’s short-term demand note borrowings from Dominion were $49 million and $79 million as of September 30, 2011 and December 31, 2010. Virginia Power’s interest charges related to its borrowings from Dominion were immaterial for the three and nine months ended September 30, 2011 and 2010.

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In March, September and October 2010, Virginia Power issued 14,600, 6,700 and 8,900 shares of its common stock to Dominion for approximately $433 million, $203 million and $277 million, respectively. The proceeds were used to pay down short-term demand note borrowings from Dominion.

Note 18. Employee Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
(millions)
Three Months Ended September 30,
Service cost	$	27		$	25		$	12		$	13
Interest cost		65			66			24			26
Expected return on plan assets		(110	)		(103	)		(21	)		(17	)
Amortization of prior service cost (credit)		—			1			(3	)		(2	)
Amortization of net loss		24			15			3			3
Net periodic benefit cost	$	6		$	4		$	15		$	23
Nine Months Ended September 30,
Service cost	$	81		$	77		$	36		$	41
Interest cost		194			200			71			76
Expected return on plan assets		(331	)		(308	)		(60	)		(52	)
Amortization of prior service cost (credit)		2			3			(10	)		(5	)
Amortization of net loss		72			45			9			9
Settlements and curtailments(1)		—			84			(1	)		37
Special termination benefits(2)		—			10			—			1
Net periodic benefit cost	$	18		$	111		$	45		$	107

(1) 2010 amounts relate to the sale of Peoples and a workforce reduction program.

(2) Represents a one-time special termination benefit for certain employees in connection with a workforce reduction program.

Employer Contributions

During the nine months ended September 30, 2011, Dominion made no contributions to its defined benefit pension plans or OPEB plans. Dominion expects to contribute approximately $18 million to its OPEB plans through Voluntary Employees’ Beneficiary Associations during the remainder of 2011.

Note 19. Operating Segments

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

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

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

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

In the nine months ended September 30, 2011, Dominion reported after-tax net expenses of $213 million for specific items in the Corporate and Other segment, with $217 million of these net expenses attributable to its operating segments. In the nine months ended September 30, 2010, Dominion reported after-tax net benefits of $905 million for specific items in the Corporate and Other segment, with $1.1 billion of these net benefits attributable to its operating segments.

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

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

• A $55 million ($39 million after-tax) impairment charge related to State Line, attributable to Dominion Generation;

• A $57 million ($34 million after-tax) charge related to the impairment of SO₂ emissions allowances not expected to be consumed due to CSAPR, attributable to Dominion Generation; and

• A $56 million ($32 million after-tax) loss from the operations of Kewaunee, attributable to Dominion Generation. Kewaunee’s results of operations have been reflected in the Corporate and Other segment due to Dominion’s decision in the first quarter of 2011 to pursue the sale of Kewaunee.

The net benefits for specific items in 2010 primarily related to the impact of the following items:

• A $2.5 billion ($1.4 billion after-tax) benefit resulting from the gain on the sale of substantially all of Dominion’s Appalachian E&P operations net of charges related to the divestiture, attributable to Dominion Energy; partially offset by

• A $338 million ($206 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program, attributable to:

• DVP ($67 million after-tax);

• Dominion Energy ($24 million after-tax); and

• Dominion Generation ($115 million after-tax);

• A $134 million ($147 million after-tax) loss from the discontinued operations of Peoples primarily reflecting a net loss on the sale, attributable to the Corporate and Other segment; and

• A $163 million ($95 million after-tax) impairment charge related to State Line, attributable to Dominion Generation.

The Corporate and Other Segment of Virginia Power primarily includes certain specific items that are not included in profit measures evaluated by executive management in assessing segment performance or allocating resources among the segments. In the nine months ended September 30, 2011 and 2010, Virginia Power reported after-tax net expenses of $126 million and $149 million, respectively, for specific items attributable to its operating segments in the Corporate and Other segment.

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

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

• A $43 million ($26 million after-tax) charge related to the impairment of SO₂ emissions allowances not expected to be consumed due to CSAPR, attributable to Dominion Generation.

The net expenses for specific items in 2010 primarily related to the impact of the following:

• A $202 million ($123 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program, attributable to:

• DVP ($63 million after-tax); and

• Dominion Generation ($60 million after-tax).

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

	DVP		Dominion Generation		Dominion Energy		Corporate and Other			Adjustments/ Eliminations			Consolidated Total
(millions)
Three Months Ended September 30,
2011
Total revenue from external customers	$	922	$	2,142	$	290	$	23		$	426		$	3,803
Intersegment revenue		21		114		341		149			(625	)		—
Total operating revenue		943		2,256		631		172			(199	)		3,803
Net income (loss) attributable to Dominion		125		394		95		(222	)		—			392
2010
Total revenue from external customers	$	907	$	2,312	$	367	$	(6	)	$	370		$	3,950
Intersegment revenue		16		114		339		172			(641	)		—
Total operating revenue		923		2,426		706		166			(271	)		3,950
Net income (loss) attributable to Dominion		107		487		92		(111	)		—			575
Nine Months Ended September 30,
2011
Total revenue from external customers	$	2,801	$	5,765	$	1,503	$	96		$	1,036		$	11,201
Intersegment revenue		134		271		843		443			(1,691	)		—
Total operating revenue		2,935		6,036		2,346		539			(655	)		11,201
Net income (loss) attributable to Dominion		389		886		368		(436	)		—			1,207
2010
Total revenue from external customers	$	2,697	$	6,121	$	1,667	$	28		$	938		$	11,451
Intersegment revenue		123		324		906		571			(1,924	)		—
Total operating revenue		2,820		6,445		2,573		599			(986	)		11,451
Loss from discontinued operations, net of tax		—		—		—		(147	)		—			(147	)
Net income attributable to Dominion		333		1,088		353		736			—			2,510

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

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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,
2011
Operating revenue	$	484	$	1,704	$	(11	)	$	2,177
Net income (loss)		127		289		(119	)		297
2010
Operating revenue	$	453	$	1,658	$	—		$	2,111
Net income (loss)		102		286		(8	)		380
Nine Months Ended September 30,
2011
Operating revenue	$	1,367	$	4,336	$	(12	)	$	5,691
Net income (loss)		342		598		(124	)		816
2010
Operating revenue	$	1,253	$	4,308	$	—		$	5,561
Net income (loss)		300		589		(147	)		742

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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 and geophysical events, including earthquakes, hurricanes, tornadoes, high winds and severe storms, that can cause outages and property damage to facilities;

• Federal, state and local legislative and regulatory developments;

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

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

• Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;

• Unplanned outages of the Companies’ facilities;

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

• Counterparty credit and performance risk;

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

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

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

• Fluctuations in interest rates;

• Changes in federal and state tax laws and regulations;

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

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

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

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

• 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;

PAGE 49

• Political and economic conditions, including inflation and deflation;

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

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

• Additional competition in electric markets in which Dominion’s merchant generation facilities operate;

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

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

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

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

• Adverse outcomes in litigation matters.

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, 2010 and in Part II, Item 1A. Risk Factors of their Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.

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

Accounting Matters

Critical Accounting Policies and Estimates

As of September 30, 2011, 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, 2010. 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:

	2011		2010		$ Change
(millions, except EPS)
Third Quarter
Net income attributable to Dominion	$	392	$	575	$	(183	)
Diluted EPS		0.69		0.98		(0.29	)
Year-To-Date
Net income attributable to Dominion	$	1,207	$	2,510	$	(1,303	)
Diluted EPS		2.10		4.23		(2.13	)

Overview

Third Quarter 2011 vs. 2010

Net income attributable to Dominion decreased by $183 million. The primary drivers include lower margins from merchant generation operations, restoration costs associated with damage caused by Hurricane Irene and a charge related to the impairment of SO₂ emissions allowances not expected to be consumed due to CSAPR.

Year-To-Date 2011 vs. 2010

Net income attributable to Dominion decreased by $1.3 billion. Unfavorable drivers include the absence of a gain on the sale of Dominion’s Appalachian E&P operations recorded in 2010, lower margins from merchant generation operations, restoration costs associated with damage caused by Hurricane Irene and the impact of less favorable weather on Dominion’s electric utility operations. Favorable drivers include the absence of charges related to a workforce reduction program and a loss on the sale of Peoples, both recorded in 2010, the impact of rate adjustment clauses on Dominion’s electric utility operations and a decrease in impairment charges related to State Line.

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Analysis of Consolidated Operations

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

	Third Quarter							Year-To-Date
	2011		2010		$ Change			2011		2010			$ Change
(millions)
Operating revenue	$	3,803	$	3,950	$	(147	)	$	11,201	$	11,451		$	(250	)
Electric fuel and other energy-related purchases		1,243		1,180		63			3,270		3,164			106
Purchased electric capacity		109		116		(7	)		344		333			11
Purchased gas		335		367		(32	)		1,342		1,550			(208	)
Net revenue		2,116		2,287		(171	)		6,245		6,404			(159	)
Other operations and maintenance		885		788		97			2,523		2,709			(186	)
Depreciation, depletion and amortization		268		263		5			785		794			(9	)
Other taxes		130		117		13			416		405			11
Gain on sale of Appalachian E&P operations		—		—		—			—		2,467			(2,467	)
Other income		16		63		(47	)		112		109			3
Interest and related charges		249		229		20			692		600			92
Income tax expense		204		374		(170	)		722		1,803			(1,081	)
Loss from discontinued operations		—		—		—			—		(147	)		147

An analysis of Dominion’s results of operations follows:

Third Quarter 2011 vs. 2010

Net revenue decreased 7% primarily reflecting:

• A $144 million decrease from merchant generation operations, primarily reflecting:

• A decline at certain nuclear generation facilities ($72 million) largely due to a decrease in realized prices ($60 million) and decreased generation ($15 million); and

• A decline at certain fossil generation facilities ($72 million) largely due to lower generation ($45 million) and a decrease in realized prices ($34 million); and

• A $34 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 $22 million increase from electric utility operations primarily reflecting:

• The impact of rate adjustment clauses ($48 million); and

• An increase in capacity revenues and a decrease in capacity expense ($12 million); partially offset by

• A decrease in sales to retail customers primarily due to a decrease in cooling degree days ($19 million); and

• A $16 million decrease related to PJM ancillary revenues reflecting anticipated billing adjustments from PJM for certain ancillary revenues recognized in 2011 and 2010 ($35 million), partially offset by other ancillary revenue increases ($19 million).

Other operations and maintenance increased 12%, primarily reflecting:

• A $121 million increase due to restoration costs associated with damage caused by Hurricane Irene; and

• A $44 million increase in impairment charges related to excess SO₂ emission allowances resulting from CSAPR; partially offset by

• A $68 million decrease in salaries, wages and benefits.

Other income decreased 75%, primarily reflecting net realized losses (net of investment income) on nuclear decommissioning trust funds in 2011 versus net realized gains (including investment income) on nuclear decommissioning trust funds in 2010.

Income tax expense decreased 45%, primarily reflecting lower pre-tax income in 2011.

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Year-To-Date 2011 vs. 2010

Net revenue decreased 2%, primarily reflecting:

• A $286 million decrease from merchant generation operations, primarily reflecting:

• A decline at certain fossil generation facilities ($145 million) largely due to lower generation ($78 million), and a decrease in realized prices ($66 million); and

• A decline at certain nuclear generation facilities ($141 million) largely due to a decrease in realized prices ($154 million), partially offset by increased generation ($18 million);

• A $125 million decrease reflecting the sale of substantially all of Dominion’s Appalachian E&P operations in April 2010.

These decreases were partially offset by:

• A $112 million increase from electric utility operations primarily reflecting:

• The impact of rate adjustment clauses ($139 million); and

• A $12 million increase due to ancillary revenues received from PJM ($47 million), partially offset by anticipated billing adjustments from PJM for certain ancillary revenues recognized in 2011 and 2010 ($35 million); partially offset by

• The impact ($45 million) of a decrease in sales to retail customers primarily due to a decrease in cooling degree days ($118 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($73 million); and

• An $87 million increase from regulated natural gas distribution operations primarily reflecting increased rider revenue related to low income assistance programs ($64 million) and increased customer usage charges ($23 million);

• A $28 million increase in retail energy marketing activities primarily due to the impact of a decrease in purchased gas expense, partially offset by an increase in purchased electric expense; and

• A $22 million increase from Dominion’s gas transmission business primarily related to an increase in revenue from NGLs.

Other operations and maintenance decreased 7%, primarily reflecting:

• A $398 million decrease primarily due to the absence of charges recorded in 2010 related to a workforce reduction program; and

• A $108 million decrease in impairment charges related to State Line.

These decreases were partially offset by:

• A $121 million increase due to restoration costs associated with damage caused by Hurricane Irene;

• A $64 million increase in bad debt expense at regulated natural gas distribution operations, primarily related to low income assistance programs. These expenses are recovered through rates and do not impact net income;

• A $64 million increase in planned outage costs primarily due to an increase in scheduled outage days at certain merchant generation facilities; and

• A $44 million increase in impairment charges related to excess SO₂ emission allowances resulting from CSAPR.

Gain on sale of Appalachian E&P operations reflects a gain on the sale of these operations.

Interest and related charges increased 15%, primarily due to the absence of a benefit recorded in 2010 resulting from the discontinuance of hedge accounting for certain interest rate derivatives.

Income tax expense decreased 60%, primarily reflecting lower federal and state taxes largely due to the absence of a gain from the sale of Dominion’s Appalachian E&P operations recorded in 2010.

Loss from discontinued operations reflects the sale of Peoples in February 2010.

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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	2011			2010			$ Change			2011			2010			$ Change
(millions, except EPS)
DVP	$	125		$	107		$	18		$	0.22		$	0.18		$	0.04
Dominion Generation		394			487			(93	)		0.69			0.83			(0.14	)
Dominion Energy		95			92			3			0.17			0.16			0.01
Primary operating segments		614			686			(72	)		1.08			1.17			(0.09	)
Corporate and Other		(222	)		(111	)		(111	)		(0.39	)		(0.19	)		(0.20	)
Consolidated	$	392		$	575		$	(183	)	$	0.69		$	0.98		$	(0.29	)
Year-To-Date
DVP	$	389		$	333		$	56		$	0.68		$	0.56		$	0.12
Dominion Generation		886			1,088			(202	)		1.54			1.84			(0.30	)
Dominion Energy		368			353			15			0.64			0.59			0.05
Primary operating segments		1,643			1,774			(131	)		2.86			2.99			(0.13	)
Corporate and Other		(436	)		736			(1,172	)		(0.76	)		1.24			(2.00	)
Consolidated	$	1,207		$	2,510		$	(1,303	)	$	2.10		$	4.23		$	(2.13	)

DVP

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

	Third Quarter							Year-To-Date
	2011		2010		% Change			2011		2010		% Change
Electricity delivered (million MWh)		23.1		23.5		(2	)%		63.9		64.8		(1	)%
Degree days (electric distribution service area):
Cooling		1,238		1,317		(6	)		1,869		2,041		(8	)
Heating		12		—		100			2,302		2,323		(1	)
Average electric distribution customer accounts (thousands)(1)		2,438		2,424		1			2,436		2,420		1
Average retail energy marketing customer accounts (thousands)(1)		2,181		2,072		5			2,154		2,019		7

(1) Period average.

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

	Third Quarter 2011 vs. 2010 Increase (Decrease)						Year-To-Date 2011 vs. 2010 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
FERC transmission equity return	$	12		$	0.03		$	32		$	0.05
Storm damage and service restoration – electric distribution operations		6			0.01			9			0.02
Salaries, wages and benefits expense		7			0.01			14			0.02
Retail energy marketing operations		(9	)		(0.02	)		14			0.03
Regulated electric sales:
Weather		(3	)		(0.01	)		(22	)		(0.04	)
Other		(3	)		(0.01	)		7			0.01
Other		8			0.02			2			0.01
Share accretion		—			0.01			—			0.02
Change in net income contribution	$	18		$	0.04		$	56		$	0.12

Dominion Generation

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

	Third Quarter							Year-To-Date
	2011		2010		% Change			2011		2010		% Change
Electricity supplied (million MWh):
Utility		23.1		23.5		(2	)%		63.9		64.8		(1	)%
Merchant(1)		11.7		12.7		(8	)		33.6		35.6		(6	)
Degree days (electric utility service area):
Cooling		1,238		1,317		(6	)		1,869		2,041		(8	)
Heating		12		—		100			2,302		2,323		(1	)

(1) Includes 1.2 and 3.3 million MWh for the quarter and year-to-date periods ended September 30, 2011, respectively, and 1.2 and 3.7 million MWh for the quarter and year-to-date periods ended September 30, 2010, respectively, related to Kewaunee.

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

	Third Quarter 2011 vs. 2010 Increase (Decrease)						Year-To-Date 2011 vs. 2010 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Merchant generation margin	$	(87	)	$	(0.14	)	$	(160	)	$	(0.28	)
Regulated electric sales:
Weather		(9	)		(0.02	)		(50	)		(0.08	)
Other		3			0.01			41			0.07
Kewaunee 2010 earnings(1)		(4	)		(0.01	)		(19	)		(0.03	)
Rate adjustment clause equity return		6			0.01			25			0.04
Outage costs		5			0.01			(22	)		(0.04	)
Other		(7	)		(0.02	)		(17	)		(0.03	)
Share accretion		—			0.02			—			0.05
Change in net income contribution	$	(93	)	$	(0.14	)	$	(202	)	$	(0.30	)

(1) Kewaunee’s 2011 results of operations have been reflected in the Corporate and Other segment due to Dominion’s decision, in the first quarter of 2011, to pursue a sale of the power station.

Dominion Energy

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

	Third Quarter							Year-To-Date
	2011		2010		% Change			2011		2010		% Change
Gas distribution throughput (bcf):
Sales		2		2		—	%		22		20		10	%
Transportation		33		32		3			188		168		12
Heating degree days (gas distribution service area)		88		78		13			3,844		3,461		11
Average gas distribution customer accounts (thousands)(1):
Sales		251		256		(2	)		253		258		(2	)
Transportation		1,029		1,029		—			1,044		1,043		—

(1) Period average.

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

	Third Quarter 2011 vs. 2010 Increase (Decrease)						Year-To-Date 2011 vs. 2010 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Gas transmission margin	$	6		$	0.01		$	9		$	0.02
Gas distribution margin		5			0.01			13			0.02
E&P disposed operations		—			—			(17	)		(0.03	)
Producer services margin		(17	)		(0.03	)		6			0.01
Other		9			0.01			4			0.01
Share accretion		—			0.01			—			0.02
Change in net income contribution	$	3		$	0.01		$	15		$	0.05

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Corporate and Other

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

	Third Quarter									Year-To-Date
	2011			2010			$ Change			2011			2010			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	(161	)	$	(4	)	$	(157	)	$	(217	)	$	1,061		$	(1,278	)
Specific items attributable to corporate operations:
Peoples discontinued operations		—			—			—			—			(147	)		147
Other		12			(24	)		36			4			(9	)		13
Total specific items		(149	)		(28	)		(121	)		(213	)		905			(1,118	)
Other corporate operations		(73	)		(83	)		10			(223	)		(169	)		(54	)
Total net benefit (expense)	$	(222	)	$	(111	)	$	(111	)	$	(436	)	$	736		$	(1,172	)
EPS impact	$	(0.39	)	$	(0.19	)	$	(0.20	)	$	(0.76	)	$	1.24		$	(2.00	)

Total Specific Items

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

Other Corporate Operations

Year-To-Date 2011 vs. 2010

Net expenses increased primarily due to the absence of a net benefit recorded in 2010 from the discontinuance of hedge accounting and subsequent changes in fair value of certain interest rate derivatives and lower consolidated state income tax benefits.

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Virginia Power

Results of Operations

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

	Third Quarter							Year-To-Date
	2011		2010		$ Change			2011		2010		$ Change
(millions)
Net income	$	297	$	380	$	(83	)	$	816	$	742	$	74

Overview

Third Quarter 2011 vs. 2010

Net income decreased by $83 million largely due to the impact of restoration costs associated with damage caused by Hurricane Irene, a charge related to the impairment of SO₂ emissions allowances not expected to be consumed due to CSAPR and less favorable weather, partially offset by the impact of rate adjustment clauses.

Year-To-Date 2011 vs. 2010

Net income increased by $74 million. Favorable drivers include the absence of charges related to a workforce reduction program recorded in 2010, the impact of rate adjustment clauses and the impact of favorable economic conditions and other factors. Unfavorable drivers include the impact of restoration costs associated with damage caused by Hurricane Irene and less favorable weather.

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Analysis of Consolidated Operations

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

	Third Quarter							Year-To-Date
	2011		2010		$ Change			2011		2010		$ Change
(millions)
Operating revenue	$	2,177	$	2,111	$	66		$	5,691	$	5,561	$	130
Electric fuel and other energy-related purchases		746		694		52			1,922		1,915		7
Purchased electric capacity		108		116		(8	)		342		331		11
Net revenue		1,323		1,301		22			3,427		3,315		112
Other operations and maintenance		514		404		110			1,172		1,240		(68	)
Depreciation and amortization		184		171		13			533		499		34
Other taxes		57		53		4			172		170		2
Other income		25		25		—			64		67		(3	)
Interest and related charges		114		88		26			290		259		31
Income tax expense		182		230		(48	)		508		472		36

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

Third Quarter 2011 vs. 2010

Net revenue increased 2%, primarily reflecting:

• The impact of rate adjustment clauses ($48 million); and

• An increase in capacity revenues and a decrease in capacity expense ($12 million); partially offset by

• A decrease in sales to retail customers primarily due to a decrease in cooling degree days ($19 million); and

• A $16 million decrease related to PJM ancillary revenues reflecting anticipated billing adjustments from PJM for certain ancillary revenues recognized in 2011 and 2010 ($35 million), partially offset by other ancillary revenue increases ($19 million).

Other operations and maintenance increased 27%, primarily reflecting:

• A $121 million increase due to restoration costs associated with damage caused by Hurricane Irene; and

• A $30 million increase in impairment charges related to excess SO₂ emission allowances resulting from CSAPR.

These increases were partially offset by:

• A $15 million decrease in salaries, wages and benefits as well as certain administrative and general costs; and

• A $13 million decrease in planned outage costs due to fewer scheduled outage days at certain electric utility generation facilities.

Interest and related charges increased 30%, primarily due to an increase in interest accrued relating to resolutions with taxing authorities ($11 million), an increase related to unfavorable changes on interest rate derivatives ($4 million), lower capitalized interest related to AFUDC as a result of construction and expansion projects ($4 million) and an overrecovery related to the debt portion of FERC transmission rates ($3 million).

Income tax expense decreased 21%, primarily reflecting lower pre-tax income in 2011.

Year-To-Date 2011 vs. 2010

Net revenue increased 3%, primarily reflecting:

• The impact of rate adjustment clauses ($139 million); and

• A $12 million increase due to ancillary revenues received from PJM ($47 million), partially offset by anticipated billing adjustments from PJM for certain ancillary revenues recognized in 2011 and 2010 ($35 million); partially offset by

• The impact ($45 million) of a decrease in sales to retail customers primarily due to a decrease in cooling degree days ($118 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($73 million).

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Other operations and maintenance decreased 5%, primarily reflecting:

• A $236 million decrease primarily due to the absence of charges recorded in 2010 related to a workforce reduction program; partially offset by

• A $121 million increase due to restoration costs associated with damage caused by Hurricane Irene; and

• A $30 million increase in impairment charges related to excess SO₂ emission allowances resulting from CSAPR.

Interest and related charges increased 12%, primarily reflecting an overrecovery related to the debt portion of FERC transmission rates ($10 million), the absence of a benefit recorded in 2010 resulting from the discontinuance of hedge accounting for certain interest rate derivatives ($6 million), an increase related to unfavorable changes on interest rate derivatives ($4 million), lower capitalized interest related to AFUDC as a result of construction and expansion projects ($5 million) and an increase from additional pollution control bond issuances in late 2010 ($4 million).

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
	2011			2010			$ Change			2011			2010			$ Change
(millions)
DVP	$	127		$	102		$	25		$	342		$	300		$	42
Dominion Generation		289			286			3			598			589			9
Primary operating segments		416			388			28			940			889			51
Corporate and Other		(119	)		(8	)		(111	)		(124	)		(147	)		23
Consolidated	$	297		$	380		$	(83	)	$	816		$	742		$	74

DVP

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

	Third Quarter							Year-To-Date
	2011		2010		% Change			2011		2010		% Change
Electricity delivered (million MWh)		23.1		23.5		(2	)%		63.9		64.8		(1	)%
Degree days (electric distribution service area):
Cooling		1,238		1,317		(6	)		1,869		2,041		(8	)
Heating		12		—		100			2,302		2,323		(1	)
Average electric distribution customer accounts (thousands)(1)		2,438		2,424		1			2,436		2,420		1

(1) Period average.

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

	Third Quarter 2011 vs.  2010 Increase (Decrease)			Year-To-Date 2011 vs. 2010 Increase (Decrease)
(millions)
FERC transmission equity return	$	12		$	32
Storm damage and service restoration – electric distribution operations		6			9
Salaries, wages and benefits expense		7			14
Regulated electric sales:
Weather		(3	)		(22	)
Other		(3	)		7
Other		6			2
Change in net income contribution	$	25		$	42

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Dominion Generation

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

	Third Quarter							Year-To-Date
	2011		2010		% Change			2011		2010		% Change
Electricity supplied (million MWh):		23.1		23.5		(2	)%		63.9		64.8		(1	)%
Degree days (electric utility service area):
Cooling		1,238		1,317		(6	)		1,869		2,041		(8	)
Heating		12		—		100			2,302		2,323		(1	)

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

	Third Quarter 2011 vs. 2010 Increase (Decrease)			Year-To-Date 2011 vs. 2010 Increase (Decrease)
(millions)
Outage costs	$	8		$	(2	)
Rate adjustment clause equity return		6			25
Regulated electric sales:
Weather		(9	)		(50	)
Other		3			41
Other		(5	)		(5	)
Change in net income contribution	$	3		$	9

Corporate and Other

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

Liquidity and Capital Resources

Dominion and Virginia Power depend on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.

At September 30, 2011, Dominion had $2.6 billion of unused capacity under its credit facilities, including $644 million of unused capacity under joint credit facilities available to Virginia Power.

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

	2011			2010
(millions)
Cash and cash equivalents at January 1	$	62		$	50
Cash flows provided by (used in):
Operating activities		2,398			1,884
Investing activities		(2,364	)		1,225
Financing activities		116			(2,713	)
Net increase in cash and cash equivalents		150			396
Cash and cash equivalents at September 30	$	212		$	446

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

	2011			2010
(millions)
Cash and cash equivalents at January 1	$	5		$	19
Cash flows provided by (used in):
Operating activities		1,697			1,238
Investing activities		(1,431	)		(1,708	)
Financing activities		(247	)		473
Net increase in cash and cash equivalents		19			3
Cash and cash equivalents at September 30	$	24		$	22

Operating Cash Flows

Net cash provided by Dominion’s operating activities increased by $514 million, primarily due to lower income tax payments, lower rate refunds related to the Virginia Settlement Approval Order and the absence of a contribution to pension plans made in 2010, partially offset by lower merchant generation margins, the impact of less favorable weather on electric utility operations, the absence of E&P operations and net changes in other working capital items.

Net cash provided by Virginia Power’s operating activities increased by $459 million, primarily due to lower income tax payments, lower rate refunds related to the Virginia Settlement Approval Order and the absence of a contribution to the Dominion pension plans made in 2010. The increase was partially offset by the impact of less favorable weather and net changes in other working capital items.

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, 2010 and Item 1A. Risk Factors in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.

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, 2011 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)	$	210	$	—	$	210
Non-investment grade(2)		5		—		5
No external ratings:
Internally rated—investment grade(3)		77		—		77
Internally rated—non-investment grade(4)		72		—		72
Total	$	364	$	—	$	364

(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 29% of the total net credit exposure.

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

(3) The five largest counterparty exposures, combined, for this category represented approximately 12% of the total net credit exposure.

(4) The five largest counterparty exposures, combined, for this category represented approximately 12% of the total net credit exposure.

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Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. 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. At September 30, 2011, Virginia Power’s exposure to potential concentrations of credit risk was not considered material.

Investing Cash Flows

For the nine months ended September 30, 2011, net cash used in Dominion’s investing activities was $2.4 billion as compared to net cash provided by investing activities of $1.2 billion in 2010, primarily reflecting the absence of the proceeds received from the sale of Dominion’s Appalachian E&P operations in April 2010 and the sale of Peoples in February 2010, partially offset by restricted cash reimbursements received in 2011 for the purpose of funding certain qualifying construction projects.

Net cash used in Virginia Power’s investing activities decreased by $277 million, primarily due to lower capital expenditures and restricted cash reimbursements for the purpose of funding certain qualifying construction projects.

Financing Cash Flows and Liquidity

Dominion and Virginia Power rely on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by their operations. As discussed further in Credit Ratings and Debt Covenants in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010, 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 business combination transactions.

For the nine months ended September 30, 2011, net cash provided by Dominion’s financing activities was $116 million as compared to net cash used in financing activities of $2.7 billion in 2010, mainly reflecting the use of proceeds from the sales of Dominion’s Appalachian E&P operations and Peoples to repay debts in 2010.

Net cash used in Virginia Power’s financing activities was $247 million as compared to net cash provided by financing activities of $473 million in 2010, primarily reflecting lower net debt issuances in 2011 as compared to 2010 as a result of higher cash flow from operations, partially offset by higher dividend payments to Dominion.

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

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In the Credit Ratings section of MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010, there is a discussion on the use of capital markets by the Companies, as well as the impact of credit ratings on the accessibility and costs of using these markets. As of September 30, 2011, there have been no changes in the Companies’ credit ratings.

Debt Covenants

In the Debt Covenants section of MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010, there is a discussion on the various covenants present in the enabling agreements underlying the Companies’ debt. Other than the amendments discussed below, as of September 30, 2011, there have been no material changes to debt covenants, nor any events of default under the Companies’ debt covenants.

In September 2011, Dominion amended the RCCs of the June 2006 hybrids and September 2006 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock issuances from 180 days to 365 days.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of September 30, 2011, 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, 2010.

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As of September 30, 2011, Dominion’s planned capital expenditures for 2012 and 2013 are expected to total approximately $4.2 billion and $3.8 billion, respectively, and Virginia Power’s planned capital expenditures for 2012 and 2013 are expected total approximately $2.5 billion and $2.9 billion, respectively. The decrease 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, 2010, primarily reflects a change in the timing of expenditures related to environmental regulation.

Use of Off-Balance Sheet Arrangements

Leasing Arrangement

Dominion leases the Fairless generating facility in Pennsylvania, which began commercial operations in June 2004. The lease expires in 2013 and, at that time, Dominion may renew the lease on terms mutually agreeable to Dominion and the lessor based on original project costs and current market conditions; purchase Fairless at its original construction cost ($898 million) plus 51% of any appraised value in excess of original construction cost; or sell Fairless, on behalf of the lessor, to an independent third party. As an operating lease, the asset and related borrowings used to finance the construction of the asset are not included in the Consolidated Balance Sheets.

Through September 30, 2011, the lessor held two power plant leases, including Fairless. In October 2011, the last lease, other than Fairless, expired and the related asset was sold by Juniper. As a result, Dominion will begin consolidating Juniper in the fourth quarter of 2011.

There have been no other material changes in the off-balance sheet arrangements disclosed in MD&A in Dominion’s Annual Report on Form 10-K for the year ended December 31, 2010.

Future Issues and Other Matters

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by, and subsequent to, the dates of Dominion’s and Virginia Power’s Consolidated Financial Statements that may impact the Companies’ future results of operations, financial condition and/or cash flows. This section should be read in conjunction with Item 1. Business and Future Issues and Other Matters in Item 7. MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010 and Future Issues and Other Matters in Dominion’s and Virginia Power’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

Regulatory Matters

See Note 14 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010 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, 2011, June 30, 2011 and in this report for additional information on various regulatory matters.

Environmental Matters

Dominion and Virginia Power are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. See Note 23 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010 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, 2011, June 30, 2011 and in this report for additional information on various environmental matters.

Air

In September 2011, the EPA announced a delay from 2011 to 2014 of its impending rulemaking to revise the ozone NAAQS, therefore NO_x controls that may have been required by the rulemaking are also expected to be delayed. However, the EPA’s decision to delay the rulemaking has been challenged in federal court and the length of delay in possible NO_x controls, if any, will depend on the outcome of that litigation.

Nuclear Matters

In August 2011, a magnitude 5.8 earthquake near Mineral, Virginia caused the two reactors at North Anna to shut down immediately, as designed. Some of the earthquake’s vibrations briefly exceeded North Anna’s licensing design basis at certain frequencies, however, Virginia Power’s inspections have shown no significant damage to equipment at the station from the earthquake. The reactors were placed in cold shutdown condition pending completion of NRC inspection and review. The restart of the two reactors is subject to NRC approval, which Virginia Power believes is likely to occur in the fourth quarter of 2011.

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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, 2010 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, 2011 and June 30, 2011 and in this report for additional information on various legal matters.

Integrated Resource Plan

Virginia Power is required to file an IRP with the Virginia Commission every two years to demonstrate how the company plans to meet projected electric demand in the next 15 years. Due to anticipated changes in federal environmental regulations currently in draft form, in September 2011, Virginia Power announced that its latest IRP incorporated the following likely actions:

• The coal-fired Chesapeake power station would likely close by 2016. Two of the four units are expected to be shut down by 2015 and the remaining two units likely would be shut down a year later;

• One coal-fired unit at Yorktown would likely close by 2015 and a second coal-fired unit would likely be converted to natural gas; and

• New air emissions controls may need to be installed on Yorktown Unit 3 and Possum Point power station Unit 5, two large oil-burning units that provide power primarily during peak demand times, depending on the final versions of federal regulations.

A final decision regarding the above generating units will be made once the proposed environmental rules are finalized.

Cove Point Export and Re-Export Projects

In September 2011, Cove Point filed the first part of a two-part domestic export authorization request with the DOE for Cove Point. The DOE approved the request in October 2011. The approval allows for long-term, multi-contract authority to liquefy for export domestically-produced LNG from the Cove Point terminal up to the equivalent of approximately 1 bcf of natural gas per day over a twenty-five year period. The approval also allows for Cove Point to act as an agent for third parties to liquefy for export domestically-produced LNG to other countries that (i) have a free trade agreement with the U.S. that includes natural gas, and (ii) possess the capacity to import LNG via ocean-going carriers.

Cove Point filed the second part of the domestic export authorization application in October 2011. In the application, Cove Point requested authority to export domestically-produced LNG to other countries (i) with which the U.S. does not prohibit free trade, but does not have a free trade agreement that includes natural gas, and (ii) that possess the capacity to import LNG via ocean-going carriers.

Cove Point is not yet committed to operating an LNG export facility. Cove Point intends to further secure customer commitments before proceeding, and regulatory approvals will also be required. Subject to a final decision on pursuing the project, as well as securing applicable regulatory approvals, construction of liquefaction facilities to convert natural gas into LNG could begin in 2014 and could be completed by the end of 2016.

In addition to the domestic export project, in August 2011, Cove Point filed an application with the DOE seeking blanket authority to re-export foreign-sourced LNG from the Cove Point terminal. Such re-exportation would be up to a cumulative total of the equivalent of 150 bcf of natural gas over a two-year period. If approved, Cove Point would be permitted to act as an agent for third parties to re-export LNG to other countries (i) other than those with which the U.S. prohibits free trade, and (ii) that possess the capacity to import LNG via ocean-going carriers. Subject to the receipt of necessary regulatory approvals, the re-export project is expected to be in service in 2012.

Collective Bargaining Agreements

In August 2011, members of the Local G-555, representing about 1,200 employees at East Ohio, ratified a new three-year labor contract with East Ohio. The current agreement remains in effect through its term ending June 15, 2012. The new contract runs through June 15, 2015.

In September 2011, members of the Local 12502, representing about 85 employees at State Line, agreed to extend the expiration date of the labor contract until March 2013. In August 2011, Dominion announced that it plans to cease operations at State Line in 2012.

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ITEM 3.

QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

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

Market Risk Sensitive Instruments and Risk Management

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

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% unfavorable change in commodity prices or interest rates.

Commodity Price Risk

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

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

A hypothetical 10% unfavorable change in commodity prices of Dominion’s non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $217 million and $183 million as of September 30, 2011 and December 31, 2010, 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 $16 million and $5 million as of September 30, 2011 and December 31, 2010, respectively.

A hypothetical 10% unfavorable change in commodity prices of Virginia Power’s non-trading commodity-based financial derivatives would not have resulted in a material change to earnings as of September 30, 2011 or December 31, 2010.

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

Interest Rate Risk

Dominion and Virginia Power manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt and interest rate swaps designated under fair value hedging and outstanding for Dominion and Virginia Power, a hypothetical 10% increase in market interest rates would not have resulted in a material change in annual earnings at September 30, 2011 or December 31, 2010.

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Additionally, Dominion and Virginia Power may use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. As of September 30, 2011, Dominion and Virginia Power had $2.29 billion and $1.29 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $34 million and $17 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at September 30, 2011. None of these interest rate derivatives were outstanding at December 31, 2010.

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

Investment Price Risk

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

Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $22 million, $63 million and $95 million for the nine months ended September 30, 2011 and 2010 and for the year ended December 31, 2010, 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 decrease in unrealized gains on these investments of $118 million for the nine months ended September 30, 2011, and a net increase in unrealized gains of $55 million for the nine months ended September 30, 2010 and $182 million for the year ended December 31, 2010.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $8 million, $29 million and $44 million for the nine months ended September 30, 2011 and 2010 and for the year ended December 31, 2010, 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 decrease in unrealized gains on these investments of $43 million for the nine months ended September 30, 2011, and a net increase in unrealized gains of $21 million for the nine months ended September 30, 2010 and $67 million for the year ended December 31, 2010.

Dominion sponsors employee pension and other postretirement benefit plans, in which Dominion’s and Virginia Power’s employees participate, that hold investments in trusts to fund benefit payments. If the values of investments held in these trusts decline, it will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of contributions to be made to the employee benefit plans.

ITEM 4. CONTROLS AND PROCEDURES

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

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, Dominion and Virginia Power are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Companies, or permits issued by various local, state and/or federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Companies and their subsidiaries are involved in various legal proceedings. Dominion and Virginia Power believe that the ultimate resolution of these proceedings will not have a material adverse effect on their financial position, liquidity or results of operations. 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, 2010. See the following for discussions on various environmental and other regulatory proceedings to which the Companies are a party:

• Notes 12 and 15 to the Consolidated Financial Statements and Future Issues in MD&A in Dominion’s and Virginia Power’s quarterly reports on Form 10-Q for the quarters ended March 31, 2011, June 30, 2011 and in this report; and

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• Notes 12 and 23 to the Consolidated Financial Statements and Future Issues in MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010.

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, 2010, 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, 2010 or their Quarterly Report on Form 10-Q for the quarter ended March 31, 2011. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Dominion

ISSUER PURCHASES OF EQUITY SECURITIES

Period	(a) Total Number  of Shares (or Units) Purchased(1)		(b) Average Price  Paid per Share (or Unit)(2)		(c) Total  Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number  (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(3)
7/1/11-7/31/11		329	$	48.27		—	19,629,059 shares/ $1.18 billion
8/1/11-8/31/11		—		—		—	19,629,059 shares/ $1.18 billion
9/1/11-9/30/11		2,708		48.74		—	19,629,059 shares/ $1.18 billion
Total		3,037	$	48.69		—	19,629,059 shares/ $1.18 billion

(1) In July and September 2011, 329 shares and 2,708 shares, respectively, were tendered by employees to satisfy tax withholding obligations on vested restricted and goal-based stock.

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

(3) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion Board of Directors 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 18, 2010 (Exhibit 3.2, Form 8-K filed May 20, 2010, 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

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

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4.2	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (filed herewith).	X
4.3	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (filed herewith).	X
10.1	First Amendment to the $3 billion Three-Year Revolving Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, the several banks and other financial institutions from time to time parties thereto, JPMorgan Chase Bank, N.A., as administrative agent, and the other agents party thereto (Exhibit 10.1, Form 8-K filed October 3, 2011, File No. 1-8489).	X	X
10.2	First Amendment to the $500 million Three-Year Revolving Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, the several banks and other financial institutions from time to time parties thereto, KeyBank National Association, as administrative agent, and the other agents party thereto (Exhibit 10.2, Form 8-K filed October 3, 2011, File No. 1-8489).	X	X
12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X
12.2a	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).		X
12.2b	Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).		X
31.a	Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.b	Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.c	Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
31.d	Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
32.a	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).	X
32.b	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X
99	Condensed consolidated earnings statements (filed herewith).	X	X

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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, 2011, filed on October 28, 2011, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, and (iv) the Notes to Consolidated Financial Statements. X X

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

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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
October 28, 2011	/s/ Ashwini Sawhney
	Ashwini Sawhney
	Vice President – Accounting and Controller (Chief Accounting Officer)
	VIRGINIA ELECTRIC AND POWER COMPANY
	Registrant
October 28, 2011	/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 18, 2010 (Exhibit 3.2, Form 8-K filed May 20, 2010, 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

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

PAGE 74

4.2	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (filed herewith).	X
4.3	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489), as amended by Amendment No. 1 to Replacement Capital Covenant dated September 26, 2011 (filed herewith).	X
10.1	First Amendment to the $3 billion Three-Year Revolving Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, the several banks and other financial institutions from time to time parties thereto, JPMorgan Chase Bank, N.A., as administrative agent, and the other agents party thereto (Exhibit 10.1, Form 8-K filed October 3, 2011, File No. 1-8489).	X	X
10.2	First Amendment to the $500 million Three-Year Revolving Credit Agreement among Dominion Resources, Inc., Virginia Electric and Power Company, the several banks and other financial institutions from time to time parties thereto, KeyBank National Association, as administrative agent, and the other agents party thereto (Exhibit 10.2, Form 8-K filed October 3, 2011, File No. 1-8489).	X	X
12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X
12.2a	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).		X
12.2b	Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).		X
31.a	Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.b	Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.c	Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
31.d	Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
32.a	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).	X
32.b	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X
99	Condensed consolidated earnings statements (filed herewith).	X	X

PAGE 75

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, 2011, filed on October 28, 2011, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, and (iv) the Notes to Consolidated Financial Statements. X X

PAGE 76

EX-4.2

Exhibit 4.2

AMENDMENT NO. 1

TO

REPLACEMENT CAPITAL COVENANT

Amendment No. 1 To Replacement Capital Covenant (“this Amendment”) dated as of September 26, 2011, by Dominion Resources, Inc., a Virginia corporation (together with its successors and assigns, the “Corporation”), to the Replacement Capital Covenant dated as of June 23, 2006 (the “June 2006 RCC”) entered into by the Corporation in favor of and for the benefit of each Covered Debtholder (as defined in the June 2006 RCC).

Recitals

A. The Corporation entered into the June 2006 RCC in connection with the issuance of $300,000,000 aggregate principal amount of its 2006 Series A Enhanced Junior Subordinated Notes Due 2066 (the “Series A Notes”).

B. Pursuant to Section 4(b) of the June 2006 RCC, the Corporation may amend the terms of the June 2006 RCC without the consent of the Covered Debtholders provided that the Board of Directors of the Corporation or a duly constituted committee thereof has determined that such amendment or supplement is not adverse to the Holders of the then effective series of Covered Debt.

C. The intent and effect of this Amendment is to change, from 180 days to 365 days, the length of the measurement period utilized for determining the Corporation’s ability to redeem or repurchase all or a portion of the Series A Notes when such determination is made via reference to the amount of net cash proceeds received by the Corporation from the issuance and sale of its Common Stock prior to such redemption or repurchase.

D. Capitalized terms not otherwise defined herein shall have the meaning given such terms in the June 2006 RCC.

NOW THEREFORE, the Corporation hereby amends the June 2006 RCC as set forth in this Amendment.

Section 1. The reference to “180 days” contained in clause (i) of Section 2 of the June 2006 RCC is hereby deleted and replaced with “365 days”.

Section 2. The reference to “180 days” contained in definition of “Applicable Percentage” contained at Schedule I of the June 2006 RCC is hereby deleted and replaced with “365 days.”

Section 3. Except as expressly amended hereby, all of the provisions of the June 2006 RCC continue in full force and effect.

Section 4. This amendment shall be governed by and construed in accordance with the laws of the State of New York.

[Signature Page Follows]

IN WITNESS WHEREOF, the Corporation has caused this Amendment to be executed by its duly authorized officer, as of the day and year first above written.

DOMINION RESOURCES, INC.
By:
	James P. Carney Vice President and Assistant Treasurer

2

EX-4.3

Exhibit 4.3

AMENDMENT NO. 1

TO

REPLACEMENT CAPITAL COVENANT

Amendment No. 1 To Replacement Capital Covenant (“this Amendment”) dated as of September 26, 2011, by Dominion Resources, lnc., a Virginia corporation (together with its successors and assigns, the “Corporation”), to the Replacement Capital Covenant dated as of September 29, 2006 (the “September 2006 RCC”) entered into by the Corporation in favor of and for the benefit of each Covered Debtholder (as defined in the September 2006 RCC).

Recitals

A. The Corporation entered into the September 2006 RCC in connection with the issuance of $500,000,000 aggregate principal amount of its 2006 Series B Enhanced Junior Subordinated Notes Due 2066 (the “Series B Notes”).

B. Pursuant to clause (ii) of Section 4(b) of the September 2006 RCC, the Corporation may amend the terms of the September 2006 RCC without the consent of the Covered Debtholders provided that such amendment or supplement is not adverse to the Holders of the then effective Covered Debt and an officer of the Corporation has delivered to the Holders of the then effective Covered Debt in the manner provided for in the indenture or other instrument under which such long-term indebtedness for money borrowed was issued a written certificate stating that, in his or her determination, such amendment or supplement is not adverse to the Holders of the then effective Covered Debt.

C. The intent and effect of this Amendment is to change, from 180 days to 365 days, the length of the measurement period utilized for determining the Corporation’s ability to redeem or repurchase all or a portion of the Series B Notes when such determination is made via reference to the amount of net cash proceeds received by the Corporation from the issuance and sale of its Common Stock prior to such redemption or repurchase.

D. Capitalized terms not otherwise defined herein shall have the meaning given such terms in the September 2006 RCC.

NOW THEREFORE, the Corporation hereby amends the September 2006 RCC as set forth in this Amendment.

Section 1. The reference to “180 days” contained in clause (i) of Section 2 of the September 2006 RCC is hereby deleted and replaced with “365 days”.

Section 2. The reference to “180 days” contained in the definition of “Applicable Percentage” contained at Schedule I of the September 2006 RCC is hereby deleted and replaced with “365 days.”

Section 3. Except as expressly amended hereby, all of the provisions of the September 2006 RCC continue in full force and effect.

Section 4. This amendment shall be governed by and construed in accordance with the laws of the State of New York.

[Signature Page Follows]

IN WITNESS WHEREOF, the Corporation has caused this Amendment to be executed by its duly authorized officer, as of the day and year first above written.

	DOMINION RESOURCES, INC.
By:
	James P. Carney
	Vice President and Assistant Treasurer

2

EX-12.1

Exhibit 12.1

Dominion Resources Inc. and Subsidiaries

Computation of Ratio of Earnings to Fixed Charges

(millions of dollars)

							Years Ended December 31,
	Nine Months Ended September 30, 2011 (a)			Twelve Months Ended September 30, 2011 (b)			2010 (c)			2009 (d)			2008(e)			2007(f)			2006(g)
Earnings, as defined:
Income from continuing operations including noncontrolling interest before income taxes, extraordinary item and cumulative effect of change in accounting principle	$	1,941		$	2,506		$	5,037		$	1,874		$	2,613		$	4,442		$	2,609
Distributed income from unconsolidated investees, less equity in earnings		(16	)		(13	)		(30	)		(30	)		(39	)		(20	)		(16	)
Fixed charges, as defined		799			1,069			971			1,022			990			1,325			1,271
Capitalized interest		(29	)		(37	)		(27	)		(18	)		(44	)		(73	)		(118	)
Preference security dividend requirement of consolidated subsidiary		(20	)		(27	)		(28	)		(24	)		(26	)		(26	)		(24	)
Total earnings, as defined	$	2,675		$	3,498		$	5,923		$	2,824		$	3,494		$	5,648		$	3,722
Fixed charges, as defined:
Interest charges	$	735		$	983		$	886		$	941		$	911		$	1,238		$	1,190
Preference security dividend requirement of consolidated subsidiary		20			27			28			24			26			26			24
Rental interest factor		44			59			57			57			53			61			57
Total fixed charges, as defined	$	799		$	1,069		$	971		$	1,022		$	990		$	1,325		$	1,271
Ratio of Earnings to Fixed Charges		3.35			3.27			6.10			2.76			3.53			4.26			2.93

(a) Earnings for the nine months ended September 30, 2011 include a $121 million of restoration costs associated with Hurricane Irene; a $57 million impairment of excess emission allowances resulting from a new EPA Air Pollution Rule; a $55 million of impairment charges related to our State Line merchant power stations; a $33 million for severance and other costs resulting from expected closings of our Salem Harbor and State Line merchant generation plants; a $21 million of earthquake related costs, largely related to inspections following the safe shutdown of reactors at our North Anna nuclear power station; a $17 million net

loss related to our investments in nuclear decommissioning trust funds; and a $20 million net charge related to other items ; partially offset by a $24 million benefit related to litigation with the Department of Energy for spent nuclear fuel-related costs at our Millstone nuclear power station. Excluding these items from the calculation would result in a higher ratio of earnings to fixed charges for the nine months ended September 30, 2011.

(b) Earnings for the twelve months ended September 30, 2011 include a $121 million of restoration costs associated with Hurricane Irene; a $57 million impairment of excess emission allowances resulting from a new EPA Air Pollution Rule; an $86 million of impairment charges related to our Salem Harbor and State Line merchant power stations; a $33 million for severance and other costs resulting from expected closings of our Salem Harbor and State Line merchant generation plants; a $21 million of earthquake related costs, largely related to inspections following the safe shutdown of reactors at our North Anna nuclear power station; and a $31 million net charge related to other items ; partially offset by a $24 million benefit related to litigation with the Department of Energy for spent nuclear fuel-related costs at our Millstone nuclear power station. Excluding these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended September 30, 2011.

(c) Earnings for the twelve months ended December 31, 2010 include a $2.4 billion benefit resulting from the sale of our Appalachian E&P operations - primarily reflecting the gain on the sale partially offset by certain transaction costs and other related charges. Earnings for the period also include a $338 million charge related to the workforce reduction program primarily reflecting severance pay and other benefits to affected employees, $194 million of charges related to our State Line and Salem Harbor merchant power stations, and a $1 million net charge related to other items. Excluding these items from the calculation would result in a lower ratio of earnings to fixed charges for the twelve months ended December 31, 2010.

(d) Earnings for the twelve months ended December 31, 2009 include a $455 million impairment charge as a result of the quarterly ceiling test performed on our gas and oil properties under the full cost method of accounting, a $712 million charge in connection with the proposed settlement of Virginia Power’s 2009 rate case proceeding and a $41 million net charge related to other items. Earnings for the period also include a $103 million reduction in other operation and maintenance expense due to a downward revision in the nuclear decommissioning asset retirement obligation for a power station that is no longer in service. Excluding these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2009.

(e) Earnings for the twelve months ended December 31, 2008 include $180 million of impairment charges reflecting other-than-temporary declines in the fair value of securities held in nuclear decommissioning trust funds, $59 million of impairment charges related to Dominion Capital, Inc. (DCI) assets, a $42 million reduction in the gain recognized in 2007 from the sale of the majority of our U.S. exploration and production (E&P) businesses as a result of post-closing adjustments, and a $30 million net charge related to other items. Excluding these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2008.

(f) Earnings for the twelve months ended December 31, 2007 include a $3.6 billion gain from the disposition of the majority of our U.S. E&P operations, partially offset by $1 billion of charges related to the disposition which are comprised of $541 million related to the discontinuance of hedge accounting for certain gas and oil derivatives and subsequent changes in the fair value of these derivatives, $171 million primarily related to the settlement of volumetric production payment agreements, $242 million of charges related to the early retirement of debt, and $91 million of employee-related expenses. Earnings for the period also include a $387 million charge related to the impairment of the partially-completed Dresden generation facility; a $231 million charge due to the termination of a power sales agreement at our State Line generating facility; $88 million of impairment charges related to DCI assets; $48 million of charges related to litigation reserves, and $70 million of charges related to other items. Fixed charges for the twelve months ended December 31, 2007 include $234 million of costs related to the early retirement of debt associated with our debt tender offer completed in July 2007. Excluding these items from the calculation would result in a lower ratio of earnings to fixed charges for the twelve months ended December 31, 2007.

(g) Earnings for the twelve months ended December 31, 2006 include $90 million of impairment charges related to DCI assets, a $60 million charge due to an adjustment eliminating the application of hedge accounting related to certain interest rate swaps associated with our junior subordinated notes payable to affiliated trusts, a $27 million charge resulting from the termination of a pipeline project in West Virginia, a $26 million impairment charge resulting from a change in method of assessing other-than-temporary decline in the fair value of certain securities, $17 million of incremental charges related to hurricanes Katrina and Rita, and $12 million of net charges related to other items. Fixed charges for the twelve months ended December 31, 2006 include a $60 million charge due to an adjustment eliminating the application of hedge accounting related to certain interest rate swaps associated with our junior subordinated notes payable to affiliated trusts. Excluding these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2006.

EX-12.2.A

Exhibit 12.2a

Virginia Electric and Power Company

Computation of Ratio of Earnings to Fixed Charges

(millions of dollars)

					Years Ended December 31,
	Nine Months Ended September  30, 2011		Twelve Months Ended September 30, 2011		2010		2009		2008		2007			2006
Earnings, as defined:
Income from continuing operations before income taxes, extraordinary item and cumulative effect of change in accounting principle	$	1,324	$	1,504	$	1,394	$	503	$	1,364	$	977		$	762
Fixed charges as defined		310		410		385		392		343		332			322
Capitalized interest		—		—		—		—		—		(4	)		(9	)
Total earnings, as defined	$	1,634	$	1,914	$	1,779	$	895	$	1,707	$	1,305		$	1,075
Fixed charges, as defined:
Interest charges	$	299	$	394	$	368	$	376	$	330	$	320		$	311
Rental interest factor		11		16		17		16		13		12			11
Total fixed charges, as defined	$	310	$	410	$	385	$	392	$	343	$	332		$	322
Ratio of Earnings to Fixed Charges		5.27		4.67		4.62		2.28		4.98		3.93			3.34

EX-12.2.B

Exhibit 12.2b

Virginia Electric and Power Company

Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends

(millions of dollars)

							Years Ended December 31,
	Nine Months Ended September  30, 2011			Twelve Months Ended September  30, 2011			2010			2009			2008			2007			2006
Earnings, as defined:
Income from continuing operations before income taxes, extraordinary item and cumulative effect of change in accounting principle	$	1,324		$	1,504		$	1,394		$	503		$	1,364		$	977		$	762
Fixed charges as defined		330			437			412			416			369			357			347
Capitalized interest		—			—			—			—			—			(4	)		(9	)
Preference security dividend requirement		(20	)		(27	)		(27	)		(24	)		(26	)		(25	)		(25	)
Total earnings, as defined	$	1,634		$	1,914		$	1,779		$	895		$	1,707		$	1,305		$	1,075
Fixed charges, as defined:
Interest charges	$	299		$	394		$	368		$	376		$	330		$	320		$	311
Preference security dividend requirement		20			27			27			24			26			25			25
Rental interest factor		11			16			17			16			13			12			11
Total fixed charges, as defined	$	330		$	437		$	412		$	416		$	369		$	357		$	347
Ratio of Earnings to Fixed Charges and Preferred Dividends		4.95			4.38			4.32			2.15			4.63			3.66			3.10

EX-31.A

Exhibit 31.a

I, Thomas F. Farrell II, certify that:

1. I have reviewed this report on Form 10-Q of Dominion Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 28, 2011	/s/    Thomas F. Farrell II
	Thomas F. Farrell II
	President and Chief Executive Officer

EX-31.B

Exhibit 31.b

I, Mark F. McGettrick, certify that:

1. I have reviewed this report on Form 10-Q of Dominion Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 28, 2011	/s/    Mark F. McGettrick
	Mark F. McGettrick
	Executive Vice President and Chief Financial Officer

EX-31.C

Exhibit 31.c

I, Thomas F. Farrell II, certify that:

1. I have reviewed this report on Form 10-Q of Virginia Electric and Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 28, 2011	/s/    Thomas F. Farrell II
	Thomas F. Farrell II
	Chief Executive Officer

EX-31.D

Exhibit 31.d

I, Mark F. McGettrick, certify that:

1. I have reviewed this report on Form 10-Q of Virginia Electric and Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 28, 2011	/s/    Mark F. McGettrick
	Mark F. McGettrick
	Executive Vice President and Chief Financial Officer

EX-32.A

Exhibit 32.a

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned officers of Dominion Resources, Inc. (the “Company”), certify that:

1. the Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 (the “Report”) of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of September 30, 2011 and for the period then ended.

/s/ Thomas F. Farrell II

Thomas F. Farrell II

President and Chief Executive Officer

October 28, 2011

/s/ Mark F. McGettrick

Mark F. McGettrick

Executive Vice President and Chief Financial Officer

October 28, 2011

EX-32.B

Exhibit 32.b

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned officers of Virginia Electric and Power Company (the “Company”), certify that:

1. the Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 (the “Report”) of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of September 30, 2011 and for the period then ended.

/s/ Thomas F. Farrell II

Thomas F. Farrell II

Chief Executive Officer

October 28, 2011

/s/ Mark F. McGettrick

Mark F. McGettrick

Executive Vice President and Chief Financial Officer

October 28, 2011

EX-99

Exhibit 99

DOMINION RESOURCES, INC.

CONDENSED CONSOLIDATED EARNINGS STATEMENT

(Unaudited)

	Twelve Months Ended September 30, 2011
(millions, except per share amounts)
Operating Revenue	$	14,946
Operating Expenses		11,688
Income from operations		3,258
Other income		172
Interest and related charges		923
Income before income tax expense including noncontrolling interests	$	2,507
Income tax expense		977
Net income including noncontrolling interests		1,530
Loss from discontinued operations (including income tax benefit of $8)		(7	)
Noncontrolling interests		17
Net income attributable to Dominion	$	1,506
Amounts attributable to Dominion:
Income from continuing operations	$	1,513
Loss from discontinued operations		(7	)
Net income attributable to Dominion	$	1,506
Earnings Per Common Share – Basic
Income from continuing operations	$	2.66
Loss from discontinued operations		(0.01	)
Noncontrolling interests		(0.03	)
Net income attributable to Dominion	$	2.62
Earnings Per Common Share – Diluted
Income from continuing operations	$	2.65
Loss from discontinued operations		(0.01	)
Noncontrolling interests		(0.03	)
Net income attributable to Dominion	$	2.61

Exhibit 99

VIRGINIA ELECTRIC AND POWER COMPANY

CONDENSED CONSOLIDATED EARNINGS STATEMENT

(Unaudited)

	Twelve Months Ended September 30, 2011
(millions)
Operating Revenue	$	7,349
Operating Expenses		5,565
Income from operations		1,784
Other income		97
Interest and related charges		377
Income before income tax expense		1,504
Income tax expense		578
Net Income		926
Preferred dividends		17
Balance available for common stock	$	909

XML

Fair Value Measurements (Gains and Losses Included in Earnings in the Level 3 Fair Value Category) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Total gains (losses) included in earnings	$ (16)	$ 27	$ (24)	$ 40
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date	7	4	29	(3)
Operating Revenue [Member]
Total gains (losses) included in earnings	(8)	5	(8)	(5)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date	7	4	29	(3)
Electric Fuel and Other Energy-Related Purchases [Member]
Total gains (losses) included in earnings	(8)	22	(16)	49
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	0	0	0	0
Purchased Gas [Member]
Total gains (losses) included in earnings	0	0	0	(4)
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	$ 0	$ 0	$ 0	$ 0

XML

Consolidated Balance Sheets (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 212		$ 62	[1]
Customer receivables	1,646		2,158	[1]
Other receivables	228		88	[1]
Inventories	1,326		1,163	[1]
Derivative assets	598		739	[1]
Other	1,257		1,190	[1]
Total current assets	5,267		5,400	[1]
Investments
Nuclear decommissioning trust funds	2,799		2,897	[1]
Investment in equity method affiliates	559		571	[1]
Restricted cash equivalents	204		400	[1]
Other	290		283	[1]
Total investments	3,852		4,151	[1]
Property, Plant and Equipment
Property, plant and equipment	42,155		39,855	[1]
Accumulated depreciation, depletion and amortization	(13,744)		(13,142)	[1]
Total property, plant and equipment, net	28,411		26,713	[1]
Deferred Charges and Other Assets
Goodwill	3,141		3,141	[1]
Regulatory assets	1,410		1,446	[1]
Other	1,949		1,966	[1]
Total deferred charges and other assets	6,500		6,553	[1]
Total assets	44,030		42,817	[1]
Current Liabilities
Securities due within one year	1,327		497	[1]
Short-term debt	783		1,386	[1]
Accounts payable	1,138		1,562	[1]
Accrued interest, payroll and taxes	647		849	[1]
Other	1,601		1,479	[1]
Total current liabilities	5,496		5,773	[1]
Long-Term Debt
Long-term debt	15,418		14,023	[1]
Junior subordinated notes payable to affiliates	268		268	[1]
Enhanced junior subordinated notes	1,467		1,467	[1]
Total long-term debt	17,153		15,758	[1]
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	5,130		4,708	[1]
Asset retirement obligations	1,654		1,577	[1]
Regulatory liabilities	1,251		1,392	[1]
Other	1,457		1,355	[1]
Total deferred credits and other liabilities	9,492		9,032	[1]
Total liabilities	32,141		30,563	[1]
Commitments and Contingencies (see Note 15)
Subsidiary Preferred Stock Not Subject to Mandatory Redemption	257		257	[1]
Common Shareholders' Equity
Common stock - no par	5,171	[2]	5,715	[1],[2]
Other paid-in capital	182		194	[1]
Retained earnings	6,778		6,418	[1]
Accumulated other comprehensive income (loss)	(499)		(330)	[1]
Total common shareholders' equity	11,632		11,997	[1]
Total liabilities and shareholders' equity	44,030		42,817	[1]
Virginia Electric and Power Company [Member]
Current Assets
Cash and cash equivalents	24		5	[3]
Customer receivables	964		905	[3]
Other receivables	137		54	[3]
Inventories	732		597	[3]
Prepayments	71		65	[3]
Other	450		355	[3]
Total current assets	2,378		1,981	[3]
Investments
Nuclear decommissioning trust funds	1,285		1,319	[3]
Restricted cash equivalents	38		169	[3]
Other	3		4	[3]
Total investments	1,326		1,492	[3]
Property, Plant and Equipment
Property, plant and equipment	28,986		27,607	[3]
Accumulated depreciation, depletion and amortization	(10,088)		(9,712)	[3]
Total property, plant and equipment, net	18,898		17,895	[3]
Deferred Charges and Other Assets
Intangible assets	176		212	[3]
Regulatory assets	387		370	[3]
Other	130		312	[3]
Total deferred charges and other assets	693		894	[3]
Total assets	23,295		22,262	[3]
Current Liabilities
Securities due within one year	15		15
Short-term debt	550		600
Accounts payable	455		499
Payables to affiliates	84		76
Affiliated current borrowings	215		103
Accrued interest, payroll and taxes	287		214
Other	651		571
Total current liabilities	2,257		2,078
Long-Term Debt
Total long-term debt	6,853		6,702
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	3,074		2,672
Asset retirement obligations	705		669
Regulatory liabilities	1,029		1,174
Other	266		203
Total deferred credits and other liabilities	5,074		4,718
Total liabilities	14,184		13,498
Commitments and Contingencies (see Note 15)
Subsidiary Preferred Stock Not Subject to Mandatory Redemption	257		257
Common Shareholders' Equity
Common stock - no par	5,738	[4]	5,738	[4]
Other paid-in capital	1,111		1,111
Retained earnings	1,990		1,634
Accumulated other comprehensive income (loss)	15		24
Total common shareholders' equity	8,854		8,507
Total liabilities and shareholders' equity	$ 23,295		$ 22,262

[1] Dominion’s Consolidated Balance Sheet at December 31, 2010 has been derived from the audited Consolidated Financial Statements at that date.

[2] 1 billion shares authorized; 570 million and 581 million shares outstanding at September 30, 2011 and December 31, 2010, respectively.

[3] Virginia Power’s Consolidated Balance Sheet at December 31, 2010 has been derived from the audited Consolidated Financial Statements at that date.

[4] 500,000 shares and 300,000 shares authorized at September 30, 2011 and December 31, 2010, respectively; 274,723 shares outstanding at both September 30, 2011 and December 31, 2010.

XML

Consolidated Balance Sheet Parentheticals (USD $) In Millions, except Share data	Sep. 30, 2011	Dec. 31, 2010
Virginia Electric and Power Company [Member]
Allowance for Doubtful Accounts Receivable, Current	$ 11	$ 11
Allowance for Doubtful Other Receivables, Current	8	6
Common Stock, Shares Authorized	500,000	300,000
Common Stock, Shares, Outstanding	274,723	274,723
Parent Company [Member]
Allowance for Doubtful Accounts Receivable, Current	28	26
Allowance for Doubtful Other Receivables, Current	$ 8	$ 9
Common Stock, Shares Authorized	1,000,000,000	1,000,000,000
Common Stock, Shares, Outstanding	570,000,000	581,000,000

XML

Employee Benefit Plans (Net Periodic Benefit Cost) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011		Sep. 30, 2010
Pension Benefits [Member]
Service cost	$ 27	$ 25	$ 81		$ 77
Interest cost	65	66	194		200
Expected return on plan assets	(110)	(103)	(331)		(308)
Amortization of prior service cost (credit)	0	1	2		3
Amortization of net loss	24	15	72		45
Settlements and curtailments			0	[1]	84	[1]
Special termination benefits			0	[2]	10	[2]
Net periodic benefit cost	6	4	18		111
Other Postretirement Benefits [Member]
Service cost	12	13	36		41
Interest cost	24	26	71		76
Expected return on plan assets	(21)	(17)	(60)		(52)
Amortization of prior service cost (credit)	(3)	(2)	(10)		(5)
Amortization of net loss	3	3	9		9
Settlements and curtailments			(1)	[1]	37	[1]
Special termination benefits			0	[2]	1	[2]
Net periodic benefit cost	$ 15	$ 23	$ 45		$ 107

[1] 2010 amounts relate to the sale of Peoples and a workforce reduction program.

[2] Represents a one-time special termination benefit for certain employees in connection with a workforce reduction program.

XML

Derivatives and Hedge Accounting Activities (Volume of Derivative Activity) (Details) (USD $)	Sep. 30, 2011
Current Derivative Contract [Member]
Interest rate	$ 1,600,000,000
Current Derivative Contract [Member] | Natural Gas [Member] | Fixed Price [Member]
Volume of natural gas	257,000,000,000	[1]
Current Derivative Contract [Member] | Natural Gas [Member] | Basis [Member]
Volume of natural gas	891,000,000,000
Current Derivative Contract [Member] | Electricity [Member] | Fixed Price [Member]
Volume of electricity	20,137,147	[1]
Current Derivative Contract [Member] | Electricity [Member] | Financial Transmission Rights [Member]
Volume of electricity	78,993,580
Current Derivative Contract [Member] | Capacity [Member]
Capacity (MW)	155,416
Current Derivative Contract [Member] | Liquids [Member]
Volume of natural gas	138,516,000	[2]
Noncurrent Derivative Contract [Member]
Interest rate	$ 2,690,000,000
Noncurrent Derivative Contract [Member] | Natural Gas [Member] | Fixed Price [Member]
Volume of natural gas	67,000,000,000	[1]
Noncurrent Derivative Contract [Member] | Natural Gas [Member] | Basis [Member]
Volume of natural gas	405,000,000,000
Noncurrent Derivative Contract [Member] | Electricity [Member] | Fixed Price [Member]
Volume of electricity	23,255,392	[1]
Noncurrent Derivative Contract [Member] | Electricity [Member] | Financial Transmission Rights [Member]
Volume of electricity	779,328
Noncurrent Derivative Contract [Member] | Capacity [Member]
Capacity (MW)	289,585
Noncurrent Derivative Contract [Member] | Liquids [Member]
Volume of natural gas	281,064,000	[2]

[1] Includes options.

[2] Includes NGLs and oil.

XML

Employee Benefit Plans

9 Months Ended

Sep. 30, 2011

Employee Benefit Plans

Employee Benefit Plans

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

	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
(millions)
Three Months Ended September 30,
Service cost	$	27		$	25		$	12		$	13
Interest cost	65			66			24			26
Expected return on plan assets	(110		)	(103		)	(21		)	(17		)
Amortization of prior service cost (credit)	—			1			(3		)	(2		)
Amortization of net loss	24			15			3			3
Net periodic benefit cost	$	6		$	4		$	15		$	23
Nine Months Ended September 30,
Service cost	$	81		$	77		$	36		$	41
Interest cost	194			200			71			76
Expected return on plan assets	(331		)	(308		)	(60		)	(52		)
Amortization of prior service cost (credit)	2			3			(10		)	(5		)
Amortization of net loss	72			45			9			9
Settlements and curtailments(1)	—			84			(1		)	37
Special termination benefits(2)	—			10			—			1
Net periodic benefit cost	$	18		$	111		$	45		$	107

(1) 2010 amounts relate to the sale of Peoples and a workforce reduction program.

(2) Represents a one-time special termination benefit for certain employees in connection with a workforce reduction program.

Employer Contributions

During the nine months ended September 30, 2011, Dominion made no contributions to its defined benefit pension plans or OPEB plans. Dominion expects to contribute approximately $18 million to its OPEB plans through Voluntary Employees' Beneficiary Associations during the remainder of 2011.

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2011
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Trading Symbol	D
Entity Registrant Name	DOMINION RESOURCES INC /VA/
Entity Central Index Key	0000715957
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	569,611,030
Virginia Electric and Power Company [Member]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Trading Symbol	VEL - PE
Entity Registrant Name	VIRGINIA ELECTRIC & POWER CO
Entity Central Index Key	0000103682
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	274,723

XML

Fair Value Measurements (Assets and Liabilities that are Measured at Fair Value on a Recurring Basis) (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	$ 3,867		$ 4,221
Derivatives			825
Total liabilities	1,120		830
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	1,951		2,092
Derivatives			12
Total liabilities	7		12
Level 1 [Member] | Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1	[1]	25	[1]
Level 1 [Member] | Restricted Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 1 [Member] | Fixed Income Securities [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 1 [Member] | Fixed Income Securities [Member] | U.S. Treasury Securities and Agency Debentures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	309	[1]	228	[1]
Level 1 [Member] | Fixed Income Securities [Member] | State and Municipal [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 1 [Member] | Fixed Income Securities [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 1 [Member] | Equity Securities [Member] | Large Cap [Member] | United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,551	[1]	1,709	[1]
Level 1 [Member] | Equity Securities [Member] | Large Cap [Member] | Non United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	11	[1]	12	[1]
Level 1 [Member] | Equity Securities [Member] | Equity Securities, Other [Member] | United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	45	[1]	56	[1]
Level 1 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	0		0
Derivatives	0		0
Level 1 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	34		62
Derivatives	7
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	1,809		2,082
Derivatives			716
Total liabilities	964		721
Level 2 [Member] | Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	69	[1]	97	[1]
Level 2 [Member] | Restricted Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	204	[1]	400	[1]
Level 2 [Member] | Fixed Income Securities [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	310	[1]	327	[1]
Level 2 [Member] | Fixed Income Securities [Member] | U.S. Treasury Securities and Agency Debentures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	175	[1]	165	[1]
Level 2 [Member] | Fixed Income Securities [Member] | State and Municipal [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	296	[1]	286	[1]
Level 2 [Member] | Fixed Income Securities [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	29	[1]	19	[1]
Level 2 [Member] | Equity Securities [Member] | Large Cap [Member] | United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 2 [Member] | Equity Securities [Member] | Large Cap [Member] | Non United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 2 [Member] | Equity Securities [Member] | Equity Securities, Other [Member] | United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 2 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	103		54
Derivatives	236		5
Level 2 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	623		734
Derivatives	728
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	107		47
Derivatives			97
Total liabilities	149		97
Level 3 [Member] | Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 3 [Member] | Restricted Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 3 [Member] | Fixed Income Securities [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 3 [Member] | Fixed Income Securities [Member] | U.S. Treasury Securities and Agency Debentures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 3 [Member] | Fixed Income Securities [Member] | State and Municipal [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 3 [Member] | Fixed Income Securities [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 3 [Member] | Equity Securities [Member] | Large Cap [Member] | United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 3 [Member] | Equity Securities [Member] | Large Cap [Member] | Non United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 3 [Member] | Equity Securities [Member] | Equity Securities, Other [Member] | United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Level 3 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	0		0
Derivatives	0		0
Level 3 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	107		47
Derivatives	149
Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	70	[1]	122	[1]
Restricted Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	204	[1]	400	[1]
Fixed Income Securities [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	310	[1]	327	[1]
Fixed Income Securities [Member] | U.S. Treasury Securities and Agency Debentures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	484	[1]	393	[1]
Fixed Income Securities [Member] | State and Municipal [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	296	[1]	286	[1]
Fixed Income Securities [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	29	[1]	19	[1]
Equity Securities [Member] | Large Cap [Member] | United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,551	[1]	1,709	[1]
Equity Securities [Member] | Large Cap [Member] | Non United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	11	[1]	12	[1]
Equity Securities [Member] | Equity Securities, Other [Member] | United States [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	45	[1]	56	[1]
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	103		54
Derivatives	236		5
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives	764		843
Derivatives	$ 884

[1] Includes investments held in the nuclear decommissioning and rabbi trusts

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Operating Revenue (Tables)

9 Months Ended

Sep. 30, 2011

Regulated and Unregulated Operating Revenue [Abstract]

Operating Revenue, Table

The Companies’ operating revenue consists of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions)
Dominion
Electric sales:
Regulated	$	2,136	$	2,083	$	5,594	$	5,488
Nonregulated	915		1,072		2,650		2,857
Gas sales:
Regulated	25		25		208		209
Nonregulated	281		375		1,220		1,502
Gas transportation and storage	291		289		1,151		1,070
Other	155		106		378		325
Total operating revenue	$	3,803	$	3,950	$	11,201	$	11,451
Virginia Power
Regulated electric sales	$	2,136	$	2,083	$	5,594	$	5,488
Other	41		28		97		73
Total operating revenue	$	2,177	$	2,111	$	5,691	$	5,561

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Fair Value Measurements (Narrative) (Details) (USD $) In Millions	3 Months Ended			1 Months Ended	9 Months Ended
	Sep. 30, 2011	Jul. 31, 2011	Sep. 30, 2011 State Line [Member] Fair Value, Measurements, Nonrecurring [Member]	Jun. 30, 2010 State Line [Member] Fair Value, Measurements, Nonrecurring [Member] Other Operating Expense [Member]	Sep. 30, 2011 Fair Value, Measurements, Nonrecurring [Member] Other Operating Expense [Member]	Sep. 30, 2011 Level 3 [Member]	Sep. 30, 2011 Level 3 [Member] Commodity Transactions [Member]
Commodity derivatives categorized as Level 3 fair value measurements, net asset							$ 42
Commodity derivatives categorized as Level 3 fair value measurements, hypothetical 10% increase in commodity prices, decrease to net asset						100
Commodity derivatives categorized as Level 3 fair value measurements, hypothetical 10% decrease in commodity prices, increase to net asset						101
So2 Emissions Allowances Obtained For Arp And Cair Compliance	57	57
Impairment of Intangible Assets (Excluding Goodwill)	57
Impairment Of Intangible Assets After Tax	34
Maximum Fair Value Of So2 Emissions Allowances	1
State line evaluation, impairment charge				163	55
State line evaluation, impairment charge after tax				95	39
State line evaluation, estimated fair value			$ 59

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Earnings Per Share

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Earnings Per Share

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,
	2011		2010		2011		2010
(millions, except EPS)
Net income attributable to Dominion	$	392	$	575	$	1,207	$	2,510
Average shares of common stock outstanding – Basic	569.4		585.0		574.2		591.7
Net effect of potentially dilutive securities(1)	1.8		1.4		1.4		1.1
Average shares of common stock outstanding – Diluted	571.2		586.4		575.6		592.8
Earnings Per Common Share – Basic	$	0.69	$	0.98	$	2.10	$	4.24
Earnings Per Common Share – Diluted	$	0.69	$	0.98	$	2.10	$	4.23

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

There were no potentially dilutive securities excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2011 and 2010.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2011

Income Tax Disclosure [Abstract]

Effective Income Tax

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,	2011		2010		2011		2010
U.S. statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.6		4.5		3.9		3.9
Legislative changes	—		1.2		—		1.3
Other, net	(1.4	)	(0.4	)	(0.5	)	(1.3	)
Effective tax rate	37.2	%	40.3	%	38.4	%	38.9	%

Schedule Of Reconciliation Of Changes In Unrecognized Tax Benefits [Table Text Block]

	Dominion			Virginia Power
(millions)
Balance at January 1, 2011	$	307		$	117
Increases - prior period positions	24			17
Decreases - prior period positions	(53		)	(33		)
Current period positions	41			23
Balance at September 30, 2011	$	319		$	124

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Income Taxes Unrecognized Tax Benefits (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
Income Taxes
Balance at January 1	$ 307
Increases - prior period positions	24
Decreases - prior period positions	(53)
Current period positions	41
Balance at September 30	$ 319

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Dispositions (Selected Information Regarding the Results of Operations of Peoples) (Details) (Peoples [Member], USD $) In Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2010
Peoples [Member]
Business Combinations [Abstract]
Operating revenue	$ 0	$ 67
Income (loss) before income taxes	$ 0	$ (134)

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Dispositions (Tables)

9 Months Ended

Sep. 30, 2011

Business Combinations [Abstract]

Schedule of selected information regarding results of operations

The following table presents selected information regarding the results of operations of Peoples, which are reported as discontinued operations in Dominion's Consolidated Statements of Income:

	Three Months  Ended September 30,		Nine Months  Ended September 30,
	2010		2010
(millions)
Operating revenue	$	—	$	67
Income (loss) before income taxes	—		(134		)

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Regulatory Matters

9 Months Ended

Sep. 30, 2011

Regulatory Matters

Regulatory Matters

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 14 to the Consolidated Financial Statements in Dominion's and Virginia Power's Annual Report on Form 10-K for the year ended December 31, 2010 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, 2011 and June 30, 2011.

Virginia Regulation

Biennial Review

In connection with its current biennial review of Virginia Power's base rates, terms and conditions, the Virginia Commission will determine whether Virginia Power's earnings for the 2009 and 2010 test years, considered as a whole, were within 50 basis points of the authorized ROE of 11.9% established in the Virginia Settlement Approval Order. The Virginia Commission will also authorize an ROE for Virginia Power that will be applied to Riders R, S, C1 and C2, as well as Riders W and B if approved, and that will be used to measure base rate earnings prospectively. In September 2011, the Virginia Commission conducted an evidentiary hearing related to the biennial review. In its testimony presented as part of the proceeding, the Virginia Commission staff proposed making several regulatory accounting and other adjustments to Virginia Power's earnings. If the Virginia Commission were to accept all of these proposed adjustments, Virginia Power would have earned an ROE of 14.11% during the 2009 and 2010 test years, resulting in a total credit to customers of approximately $143 million. Virginia Power believes that the adjustments proposed by the Virginia Commission staff were improper and inconsistent with prior Virginia Power regulatory precedent and the terms of the 2010 Virginia Settlement Approval Order. Due to the uncertainty surrounding the Virginia Commission's final ruling and since Virginia Power believes it earned an ROE of 12.1%, which is within the allowed range, during the 2009 and 2010 test years, Virginia Power has not recognized a liability related to the staff's recommendation as of September 30, 2011.

Virginia Power is requesting authorization of a prospective ROE of 12.5%, inclusive of a performance incentive of 100 basis points as provided for by the Regulation Act. In its filed and direct testimony presented as part of the evidentiary hearing, the Virginia Commission staff recommended a prospective ROE of 10.67%, inclusive of an RPS performance incentive of 50 basis points. The staff's recommended ROE is equal to the minimum ROE permitted by the staff's interpretation of the Regulation Act. Pursuant to the Regulation Act, Virginia Power's authorized ROE, exclusive of any performance or other statutory incentive, can be no lower than the average of the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., with certain limitations as described in the Regulation Act.

A final order in the 2011 biennial review for base rates must be issued no later than November 30, 2011.

DSM Riders C1 and C2

In September 2011, Virginia Power filed with the Virginia Commission an application for approval of six new energy efficiency DSM programs. Virginia Power also filed an annual update to Riders C1 and C2, with a proposed revenue requirement of approximately $86 million for the period May 1, 2012 through April 30, 2013. This revenue requirement includes the new DSM programs, five previously-approved DSM programs, and a previously-approved electric vehicle pilot program. The proposed revenue requirement represents an approximately $68 million increase over the revenue requirement approved in the 2010 Riders C1 and C2 proceeding and includes approximately $26 million to recover projected lost revenues associated with energy efficiency programs. The filing utilizes a 12.5% placeholder ROE pending the Virginia Commission's determination in the 2011 biennial review.

Mt. Storm-to-Doubs Line

In September 2011, the Virginia Commission approved Virginia Power's application to rebuild its portion of the Mt. Storm-to-Doubs line. Subject to applicable state and federal regulatory approvals, Virginia Power's portion of the rebuild project is expected to cost approximately $350 million and is expected to be completed by June 2015.

North Anna COL

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna, which Virginia Power owns along with ODEC. In February 2011, ODEC informed Virginia Power of its intent to no longer participate in the development of a potential new unit at North Anna. Virginia Power and ODEC are currently working together to finalize the terms and conditions of such withdrawal.

Virginia Power has not yet committed to building a new nuclear unit at North Anna. If Virginia Power decides to build the 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 continues to pursue the COL from the NRC. The current NRC schedule for issuance of the COL is 2013.

The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the ASLB of the NRC permitted BREDL to intervene in the proceeding. All of BREDL's previous contentions in this proceeding have been dismissed. In September 2011, BREDL submitted a new proposed contention seeking to litigate issues related to the August 2011 Mineral, Virginia earthquake. In October 2011, the ASLB granted a motion filed by Virginia Power, BREDL and the NRC staff to hold any ruling on this proposed contention in abeyance until Virginia Power completes an assessment of this earthquake. No other persons have sought to intervene in the proceeding. If a new contention is not admitted, the mandatory NRC hearing will be uncontested with respect to other issues.

On April 14, 2011, twenty-one organizations and individuals that had previously intervened opposing various reactor licensing proceedings filed a petition requesting that the NRC suspend all decisions regarding reactor licensing and design certification pending completion of an NRC task force review of the events at Fukushima, Japan, among other requested relief. The North Anna 3 COL proceeding is one of the pending proceedings identified in this petition, and BREDL served the petition in the North Anna 3 COL proceeding on April 18, 2011. In September 2011, the NRC denied the petitioners' requests to suspend licensing and design certification proceedings. The only relief granted was the petitioners' request that the NRC perform a safety analysis of the regulatory implications of the Fukushima event to the extent it is doing so.

North Carolina Regulation

In August 2011, Virginia Power filed its annual fuel expense recovery application with the North Carolina Commission. The application requests a revenue increase of approximately $37 million, including approximately $14 million of previously deferred fuel costs. If approved, revised fuel rates would go into effect January 1, 2012.

FERC Gas Regulation

Ellisburg-to-Craigs Project

In September 2011, FERC approved DTI's proposed Ellisburg-to-Craigs project. The project is expected to have capacity of approximately 150,000 dekatherms per day, which will be leased by TGP to move Marcellus shale natural gas supplies from TGP's 300 Line pipeline system in northern Pennsylvania to its 200 Line pipeline system in upstate New York. The project is expected to cost approximately $46 million. Subject to receipt of FERC approval to commence construction, construction of additional compression facilities and a new measurement and regulating station is expected to begin in March 2012, with a projected in-service date of November 2012.

Northeast Expansion Project

In August 2011, DTI received FERC authorization for the Northeast Expansion Project. The project is expected to provide approximately 200,000 dekatherms per day of firm transportation services for CONSOL's Marcellus Shale natural gas production from various receipt points in central and southwestern Pennsylvania to a nexus of market pipelines and storage facilities in Leidy, Pennsylvania. The project is expected to cost approximately $100 million. Subject to receipt of FERC approval to commence construction, construction of new compression facilities at three existing compressor stations in central Pennsylvania is expected to begin in March 2012, with a projected in-service date of November 2012.

Ohio Regulation

In March 2011, East Ohio filed a request with the Ohio Commission to accelerate the PIR program. In August 2011, the Ohio Commission approved the stipulation filed in East Ohio's accelerated PIR proceeding. The stipulation provides for an increase in annual PIR capital investment from the current level of approximately $120 million stepping up to approximately $160 million by 2013. In addition, the stipulation provides for cost recovery over a five-year period commencing upon the approval of the Ohio Commission. In accordance with the stipulation, East Ohio requested the dismissal of its appeal at the Ohio Supreme Court regarding its opposition to the Ohio Commission's order concerning East Ohio's first year PIR cost recovery charge.

In August 2011, East Ohio submitted its annual application to adjust the cost recovery charge under the previously approved PIR program. A supplement to the application was filed in September 2011. The proposed recovery charge includes actual costs and a return related to investments made through June 30, 2011. A settlement agreement filed with the Ohio Commission in October 2011 supports the revenue requirement of $37 million reflected in the application.

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Dispositions

9 Months Ended

Sep. 30, 2011

Business Combinations [Abstract]

Dispositions

Dispositions

Sale of Appalachian E&P Operations

In April 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. The transaction included the mineral rights to approximately 491,000 acres in the Marcellus Shale formation. Dominion retained certain oil and natural gas wells located on or near its natural gas storage fields. The transaction generated after-tax proceeds of approximately $2.2 billion and resulted in an after-tax gain of approximately $1.4 billion, which included a $134 million write-off of goodwill, recorded in the second quarter of 2010.

The results of operations for Dominion's Appalachian E&P business are not reported as discontinued operations in the Consolidated Statements of Income since Dominion did not sell its entire U.S. cost pool.

Due to the sale, hedge accounting was discontinued for certain cash flow hedges since it became probable that the forecasted sales of natural gas would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a $42 million ($25 million after-tax) benefit, recorded in operating revenue in its Consolidated Statement of Income, reflecting the reclassification of gains from AOCI to earnings for these contracts in March 2010.

Sale of Peoples

In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The sale resulted in an after-tax loss of approximately $140 million, including post-closing adjustments, and a $79 million write-off of goodwill. The sale also resulted in after-tax expenses of approximately $27 million, including transaction and benefit-related costs. Prior to the sale, Peoples had income from operations of $12 million after-tax during 2010.

The following table presents selected information regarding the results of operations of Peoples, which are reported as discontinued operations in Dominion's Consolidated Statements of Income:

	Three Months  Ended September 30,		Nine Months  Ended September 30,
	2010		2010
(millions)
Operating revenue	$	—	$	67
Income (loss) before income taxes	—		(134		)

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2011

Compensation and Retirement Disclosure [Abstract]

Net Periodic Benefit Cost

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

	Pension Benefits						Other Postretirement Benefits
	2011			2010			2011			2010
(millions)
Three Months Ended September 30,
Service cost	$	27		$	25		$	12		$	13
Interest cost	65			66			24			26
Expected return on plan assets	(110		)	(103		)	(21		)	(17		)
Amortization of prior service cost (credit)	—			1			(3		)	(2		)
Amortization of net loss	24			15			3			3
Net periodic benefit cost	$	6		$	4		$	15		$	23
Nine Months Ended September 30,
Service cost	$	81		$	77		$	36		$	41
Interest cost	194			200			71			76
Expected return on plan assets	(331		)	(308		)	(60		)	(52		)
Amortization of prior service cost (credit)	2			3			(10		)	(5		)
Amortization of net loss	72			45			9			9
Settlements and curtailments(1)	—			84			(1		)	37
Special termination benefits(2)	—			10			—			1
Net periodic benefit cost	$	18		$	111		$	45		$	107

(1) 2010 amounts relate to the sale of Peoples and a workforce reduction program.

(2) Represents a one-time special termination benefit for certain employees in connection with a workforce reduction program.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Measurements

Fair Value Measurements

Dominion's and Virginia Power's fair value measurements are made in accordance with the policies discussed in Note 7 to the Consolidated Financial Statements in their Annual Report on Form 10-K for the year ended December 31, 2010. See Note 10 in this report for further information about their derivatives and hedge accounting activities.

At September 30, 2011, Dominion's and Virginia Power's net balance of commodity derivatives categorized as Level 3 fair value measurements was a net liability of $42 million and $21 million, respectively. A hypothetical 10% increase in commodity prices would increase Dominion's and Virginia Power's Level 3 net liability by $100 million and $7 million, respectively, while a hypothetical 10% decrease in commodity prices would decrease Dominion's and Virginia Power's Level 3 net liability by $101 million and $7 million, respectively.

Non-recurring Fair Value Measurements

In September 2010, Virginia Power evaluated its SO₂ emissions allowances not expected to be consumed by its generating units for potential impairment due to the significant decline in market prices since the July 2010 release of the EPA's proposed replacement rule for CAIR, ultimately known as CSAPR. As a result of this evaluation, Virginia Power recorded an impairment charge of $13 million ($8 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down its SO₂ emissions allowances not expected to be consumed to their estimated fair value of less than $1 million. In the third quarter of 2011, Dominion and Virginia Power evaluated their SO₂ emissions allowances not expected to be consumed by generating units for potential impairment due to the EPA's issuance of CSAPR as discussed in Note 15. Prior to the issuance of CSAPR, Dominion and Virginia Power held $57 million and $43 million, respectively, of SO₂ emissions allowances obtained for ARP and CAIR compliance. Due to CSAPR's establishment of a new allowance program and the elimination of CAIR, Dominion and Virginia Power have more SO₂ emissions allowances than needed for ARP compliance. As a result of this evaluation, Dominion and Virginia Power recorded an impairment charge of $57 million ($34 million after-tax) and $43 million ($26 million after-tax), respectively, in other operations and maintenance expense in their Consolidated Statements of Income, to write down these emissions allowances to their estimated fair value of less than $1 million. To estimate the value of these emissions allowances in both impairment tests, Dominion utilized a market approach by obtaining broker quotes to validate CSAPR's impact on emissions allowance prices. However, due to limited market activity for future SO₂ vintage year allowances, these are considered a Level 3 fair value measurement.

In June 2010, Dominion evaluated State Line for impairment due to the station's relatively low level of profitability combined with the EPA's issuance of a new stringent 1-hour primary NAAQS for SO₂ that would likely require significant environmental capital expenditures in the future. As a result of this evaluation, Dominion recorded an impairment charge of $163 million ($95 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down State Line's long-lived assets to their estimated fair value of $59 million. During March 2011, Dominion determined that it was unlikely that State Line would participate in the May 2011 PJM capacity base residual auction that would commit State Line's capacity from June 2014 through May 2015.  This determination reflected an expectation that margins for coal-fired generation will remain compressed in the 2014 and 2015 period in combination with the expectation that State Line may be impacted during the same time period by environmental regulations that would likely require significant capital expenditures. As a result, Dominion evaluated State Line for impairment since it was more likely than not that State Line would be retired before the end of its previously estimated useful life. As a result of this evaluation, Dominion recorded an impairment charge of $55 million ($39 million after-tax) reflected in other operations and maintenance expense in its Consolidated Statement of Income, to write down State Line's long-lived assets to their estimated fair value of less than $1 million. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of State Line's long-lived assets in both impairment tests. These were considered Level 3 fair value measurements due to the use of significant unobservable inputs including estimates of future power and other commodity prices.

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, 2011
Assets
Derivatives:
Commodity	$	34	$	623	$	107	$	764
Interest rate	—		103		—		103
Investments(1):
Equity securities:
U.S.:
Large cap	1,551		—		—		1,551
Other	45		—		—		45
Non-U.S.:
Large cap	11		—		—		11
Fixed Income:
Corporate debt instruments	—		310		—		310
U.S. Treasury securities and agency debentures	309		175		—		484
State and municipal	—		296		—		296
Other	—		29		—		29
Cash equivalents and other	1		69		—		70
Restricted cash equivalents	—		204		—		204
Total assets	$	1,951	$	1,809	$	107	$	3,867
Liabilities
Derivatives:
Commodity	$	7	$	728	$	149	$	884
Interest Rate	—		236		—		236
Total liabilities	$	7	$	964	$	149	$	1,120
At December 31, 2010
Assets
Derivatives:
Commodity	$	62	$	734	$	47	$	843
Interest rate	—		54		—		54
Investments(1):
Equity securities:
U.S.:
Large cap	1,709		—		—		1,709
Other	56		—		—		56
Non-U.S.:
Large cap	12		—		—		12
Fixed Income:
Corporate debt instruments	—		327		—		327
U.S. Treasury securities and agency debentures	228		165		—		393
State and municipal	—		286		—		286
Other	—		19		—		19
Cash equivalents and other	25		97		—		122
Restricted cash equivalents	—		400		—		400
Total assets	$	2,092	$	2,082	$	47	$	4,221
Liabilities
Derivatives:
Commodity	$	12	$	716	$	97	$	825
Interest rate	—		5		—		5
Total liabilities	$	12	$	721	$	97	$	830

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

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,
	2011			2010			2011			2010
(millions)
Beginning balance	$	(122	)	$	32		$	(50	)	$	(66	)
Total realized and unrealized gains (losses):
Included in earnings	(16		)	27			(24		)	40
Included in other comprehensive income (loss)	75			(65		)	16			20
Included in regulatory assets/liabilities	(3		)	(13		)	(35		)	1
Settlements	24			(23		)	47			(41		)
Transfers out of Level 3	—			25			4			29
Ending balance	$	(42	)	$	(17	)	$	(42	)	$	(17	)
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	$	7		$	4		$	29		$	(3	)

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

	Operating revenue			Electric fuel and other energy-related purchases			Purchased  gas			Total
(millions)
Three Months Ended September 30, 2011
Total gains (losses) included in earnings	$	(8	)	$	(8	)	$	—		$	(16	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date	7			—			—			7
Three Months Ended September 30, 2010
Total gains (losses) included in earnings	$	5		$	22		$	—		$	27
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	4			—			—			4
Nine Months Ended September 30, 2011
Total gains (losses) included in earnings	$	(8	)	$	(16	)	$	—		$	(24	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date	29			—			—			29
Nine Months Ended September 30, 2010
Total gains (losses) included in earnings	$	(5	)	$	49		$	(4	)	$	40
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	(3		)	—			—			(3		)

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, 2011
Assets
Derivatives:
Commodity	$	—	$	1	$	2	$	3
Investments(1):
Equity securities:
U.S.:
Large cap	613		—		—		613
Other	20		—		—		20
Fixed income:
Corporate debt instruments	—		189		—		189
U.S. Treasury securities and agency debentures	146		50		—		196
State and municipal	—		100		—		100
Other	—		22		—		22
Cash equivalents and other	—		47		—		47
Restricted cash equivalents	—		38		—		38
Total assets	$	779	$	447	$	2	$	1,228
Liabilities
Derivatives:
Commodity	$	—	$	6	$	23	$	29
Interest Rate	—		82		—		82
Total liabilities	$	—	$	88	$	23	$	111
At December 31, 2010
Assets
Derivatives:
Commodity	$	—	$	12	$	15	$	27
Investments(1):
Equity securities:
U.S.:
Large cap	676		—		—		676
Other	25		—		—		25
Fixed Income:
Corporate debt instruments	—		215		—		215
U.S. Treasury securities and agency debentures	80		63		—		143
State and municipal	—		102		—		102
Other	—		15		—		15
Cash equivalents and other	10		61		—		71
Restricted cash equivalents	—		169		—		169
Total assets	$	791	$	637	$	15	$	1,443
Liabilities
Derivatives:
Commodity	$	—	$	5	$	1	$	6
Total liabilities	$	—	$	5	$	1	$	6

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

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,
	2011			2010			2011			2010
(millions)
Beginning balance	$	(18	)	$	5		$	14		$	(10	)
Total realized and unrealized gains (losses):
Included in earnings	(8		)	22			(16		)	48
Included in regulatory assets/liabilities	(3		)	(13		)	(35		)	2
Settlements	8			(22		)	16			(48		)
Ending balance	$	(21	)	$	(8	)	$	(21	)	$	(8	)

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, 2011 and 2010. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and nine months ended September 30, 2011 and 2010.

Fair Value of Financial Instruments

Substantially all of Dominion’s and Virginia Power’s financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, customer and other receivables, short-term debt and accounts payable are representative of fair value because of the short-term nature of these instruments. For Dominion’s and Virginia Power’s financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

	September 30, 2011				December 31, 2010
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	16,745	$	19,381	$	14,520	$	16,112
Junior subordinated notes payable to affiliates	268		275		268		261
Enhanced junior subordinated notes	1,467		1,539		1,467		1,560
Subsidiary preferred stock(3)	257		262		257		249
Virginia Power
Long-term debt, including securities due within one year(2)	$	6,868	$	8,233	$	6,717	$	7,489
Preferred stock(3)	257		262		257		249

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

(2) Includes amounts which represent the unamortized discount and premium. At September 30, 2011 and December 31, 2010, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt of approximately $103 million and $49 million, respectively.

(3) Includes issuance expenses of $2 million at September 30, 2011 and December 31, 2010.

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Significant Financing Transactions

9 Months Ended

Sep. 30, 2011

Significant Financing Transactions

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, 2011, Dominion’s commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:

	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility(1)	$	3,000	$	783	$	—	$	2,217
Joint revolving credit facility(2)	500		—		127		373
Total	$	3,500	$	783	$	127	$	2,590

(1) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. 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) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

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

At September 30, 2011, Virginia Power’s share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion were as follows:

	Facility Sub-limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility(1)	$	1,000	$	550	$	—	$	450
Joint revolving credit facility(2)	250		—		56		194
Total	$	1,250	$	550	$	56	$	644

(1) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. 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 applicable sub-limit under this credit facility can be increased or decreased multiple times per year.

(2) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s applicable sub-limit under this credit facility can be increased or decreased multiple times per year.

In addition to the credit facility commitments disclosed above, Virginia Power also has a $120 million credit facility that was entered into in September 2010 with an originial maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This facility supports certain tax-exempt financings of Virginia Power.

Long-term Debt

In August 2011, Dominion issued $500 million of 4.9% senior notes that mature in 2041 and $450 million of 1.95% senior notes that mature in 2016. The proceeds were used for general corporate purposes including the repayment of short-term debt.

In December 2010, Brayton Point borrowed $160 million and $75 million in connection with the Massachusetts Development Finance Agency Recovery Zone Facility Bonds, Series 2010 A and the Solid Waste Disposal Revenue Bonds, Series 2010 B, respectively, which mature in 2041. The proceeds are being used to finance certain qualifying facilities at Brayton Point. Due to unfavorable market conditions, Dominion acquired the bonds upon issuance in December 2010 with the intention of remarketing them to third parties at a later time. At December 31, 2010, these bonds had not been remarketed and thus were not reflected on the Consolidated Balance Sheets. In July 2011, the Series 2010 B bonds were remarketed to a third party using a remarketing process, and bear interest at a variable rate for the first five years, after which they will bear interest at a market rate to be determined at that time. In August 2011, the Series 2010 A bonds were remarketed to third parties using a remarketing process, and bear interest at a coupon rate of 2.25% for the first five years, after which they will bear interest at a market rate to be determined at that time.

In March 2011, Dominion issued $500 million of 4.45% senior notes that mature in 2021 and $400 million of 1.80% senior notes that mature in 2014. The proceeds were used for general corporate purposes including the repayment of short-term debt.

In December 2010 and September 2009, Virginia Power borrowed $100 million and $60 million, respectively, in connection with the $160 million Industrial Development Authority of Wise County Solid Waste and Sewage Disposal Revenue Bonds, Series 2009 A, which mature in 2040. The proceeds are being used to finance certain qualifying facilities at the Virginia City Hybrid Energy Center. Due to unfavorable market conditions, Virginia Power acquired the bonds upon issuance with the intention of remarketing them to third parties at a later time. At December 31, 2010, these bonds had not been remarketed and thus were not reflected on the Consolidated Balance Sheets. In March 2011, the bonds were remarketed to a third party and bear interest at a variable rate for the first five years, after which they will bear interest at a market rate to be determined at that time.

Convertible Securities

At September 30, 2011, Dominion had $165 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, 2011, the conversion rate has been adjusted, primarily due to individual dividend payments above the level paid at issuance, to 28.8178 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $34.70.

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, 2011 approximately $37 million of the contingent convertible senior notes were converted by holders. The senior notes are eligible for conversion during the fourth quarter of 2011.

Issuance of Common Stock

Dominion maintains Dominion Direct® and a number of employee savings plans through which employer and employee contributions may be invested in the Company's common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans by employees, Dominion Direct® participants and the Company.

Since February 2010, Dominion Direct® and the Dominion employee savings plans have been purchasing Dominion common stock on the open market with the proceeds received through these programs, rather than having additional new common shares issued.

During the nine months ended September 30, 2011, Dominion issued approximately 1 million shares of common stock and received cash proceeds of $37 million through the exercise of employee stock options.

Repurchase of Common Stock

In the first quarter of 2011, Dominion announced that it expected to repurchase between $600 million and $700 million of common stock with cash tax savings resulting from the extension of the bonus depreciation allowance discussed in Note 6 to the Consolidated Financial Statements in Dominion's and Virginia Power's Annual Report on Form 10-K for the year ended December 31, 2010. During the nine months ended September 30, 2011, Dominion repurchased approximately 13 million shares of common stock for approximately $601 million on the open market under this program, at an average price of $46.37 per share. In October 2011, Dominion determined that it does not plan to repurchase additional shares under this program.

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Operating Segments (Schedule of Segment Reporting Information, by Segment) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Total revenue from external customers	$ 3,803	$ 3,950	$ 11,201	$ 11,451
Intersegment revenue	0	0	0	0
Total operating revenue	3,803	3,950	11,201	11,451
Loss from discontinued operations, net of tax	0	0	0	(147)
Net income (loss) attributable to Dominion	392	575	1,207	2,510
Dominion Virginia Power [Member]
Total revenue from external customers	922	907	2,801	2,697
Intersegment revenue	21	16	134	123
Total operating revenue	943	923	2,935	2,820
Loss from discontinued operations, net of tax				0
Net income (loss) attributable to Dominion	125	107	389	333
Dominion Generation [Member]
Total revenue from external customers	2,142	2,312	5,765	6,121
Intersegment revenue	114	114	271	324
Total operating revenue	2,256	2,426	6,036	6,445
Loss from discontinued operations, net of tax				0
Net income (loss) attributable to Dominion	394	487	886	1,088
Dominion Energy [Member]
Total revenue from external customers	290	367	1,503	1,667
Intersegment revenue	341	339	843	906
Total operating revenue	631	706	2,346	2,573
Loss from discontinued operations, net of tax				0
Net income (loss) attributable to Dominion	95	92	368	353
Corporate and Other [Member]
Total revenue from external customers	23	(6)	96	28
Intersegment revenue	149	172	443	571
Total operating revenue	172	166	539	599
Loss from discontinued operations, net of tax				(147)
Net income (loss) attributable to Dominion	(222)	(111)	(436)	736
Adjustments/Eliminations [Member]
Total revenue from external customers	426	370	1,036	938
Intersegment revenue	(625)	(641)	(1,691)	(1,924)
Total operating revenue	(199)	(271)	(655)	(986)
Loss from discontinued operations, net of tax				0
Net income (loss) attributable to Dominion	$ 0	$ 0	$ 0	$ 0

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Derivatives and Hedge Accounting Activities

9 Months Ended

Sep. 30, 2011

Derivatives and Hedge Accounting Activities

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, 2010. See Note 9 in this report for further information about fair value measurements and associated valuation methods for derivatives.

Dominion

The following table presents the volume of Dominion’s derivative activity as of September 30, 2011. 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 deals, 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)	257		67
Basis	891		405
Electricity (MWh):
Fixed price(1)	20,137,147		23,255,392
FTRs	78,993,580		779,328
Capacity (MW)	155,416		289,585
Liquids (gallons)(2)	138,516,000		281,064,000
Interest rate	$	1,600,000,000	$	2,690,000,000

(1) Includes options.

(2) Includes NGLs and oil.

For the three and nine months ended September 30, 2011 and 2010, gains or losses on hedging instruments determined to be ineffective were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices and were not material for the three and nine months ended September 30, 2011 and 2010.

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, 2011:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(19	)	$	(7	)	39 months
Electricity	38			21			51 months
NGLs	(39		)	(24		)	39 months
Other	6			1			44 months
Interest rate	(107		)	(5		)	375 months
Total	$	(121	)	$	(14	)

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.

The sale of the majority of Dominion’s remaining E&P operations during 2010 resulted in the discontinuance of hedge accounting for certain cash flow hedges, as discussed in Note 3.

In addition, changes to Dominion's financing needs during the first and second quarters of 2010 resulted in the discontinuance of hedge accounting for certain cash flow hedges, since it became probable that forecasted interest payments would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a benefit recorded to interest and related charges reflecting the reclassification of gains from AOCI to earnings of $110 million ($67 million after-tax) in the nine months ended September 30, 2010. The reclassification of gains from AOCI to earnings was partially offset by subsequent changes in fair value of $37 million ($23 million after-tax) for the nine months ended September 30, 2010.

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, 2011
ASSETS
Current Assets
Commodity	$	150	$	412	$	562
Interest rate	36		—		36
Total current derivative assets	186		412		598
Noncurrent Assets
Commodity	105		97		202
Interest rate	67		—		67
Total noncurrent derivative assets(1)	172		97		269
Total derivative assets	$	358	$	509	$	867
LIABILITIES
Current Liabilities
Commodity	$	186	$	476	$	662
Interest rate	124		7		131
Total current derivative liabilities(2)	310		483		793
Noncurrent Liabilities
Commodity	119		103		222
Interest rate	74		31		105
Total noncurrent derivative liabilities(3)	193		134		327
Total derivative liabilities	$	503	$	617	$	1,120
December 31, 2010
ASSETS
Current Assets
Commodity	$	291	$	425	$	716
Interest rate	23		—		23
Total current derivative assets	314		425		739
Noncurrent Assets
Commodity	44		83		127
Interest rate	31		—		31
Total noncurrent derivative assets(1)	75		83		158
Total derivative assets	$	389	$	508	$	897
LIABILITIES
Current Liabilities
Commodity	$	178	$	455	$	633
Total current derivative liabilities(2)	178		455		633
Noncurrent Liabilities
Commodity	86		106		192
Interest rate	5		—		5
Total noncurrent derivative liabilities(3)	91		106		197
Total derivative liabilities	$	269	$	561	$	830

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

(2) Current derivative liabilities are presented in other current liabilities in Dominion's Consolidated Balance Sheets.

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

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, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	28
Purchased gas				(7		)
Electric fuel and other energy-related purchases				2
Total commodity	$	69		23			$	(1	)
Interest rate(3)	(204		)	(8		)	(76		)
Total	$	(135	)	$	15		$	(77	)
Three Months Ended September 30, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	88
Purchased gas				(6		)
Electric fuel and other energy-related purchases				4
Purchased electric capacity				1
Total commodity	$	(5	)	87			$	(6	)
Interest rate(3)	—			—			1
Foreign currency(4)	—			—			—
Total	$	(5	)	$	87		$	(5	)
Nine Months Ended September 30, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	88
Purchased gas				(61		)
Electric fuel and other energy-related purchases				4
Purchased electric capacity				1
Total commodity	$	(24	)	32			$	(10	)
Interest rate(3)	(236		)	(8		)	(76		)
Total	$	(260	)	$	24		$	(86	)
Nine Months Ended September 30, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	383
Purchased gas				(122		)
Electric fuel and other energy-related purchases				(4		)
Purchased electric capacity				3
Total commodity	$	277		260			$	(17	)
Interest rate(3)	(3		)	109			(23		)
Foreign currency(4)	—			1			(2		)
Total	$	274		$	370		$	(42	)

(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.

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

	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	2011			2010			2011			2010
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	15		$	45		$	56		$	71
Purchased gas	(10		)	(13		)	(28		)	(42		)
Electric fuel and other energy-related purchases	(8		)	23			(16		)	48
Interest rate(2)	(4		)	—			(4		)	(37		)
Total	$	(7	)	$	55		$	8		$	40

(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.

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Investments (Tables)

9 Months Ended

Sep. 30, 2011

Investments, Debt and Equity Securities [Abstract]

Available-For-Sale Securities

Dominion’s decommissioning trust funds are summarized below.

	Amortized Cost		Total  Unrealized Gains(1)		Total  Unrealized Losses (1)				Fair Value
(millions)
September 30, 2011
Marketable equity securities
U.S.:
Large Cap	$	1,147	$	377	$	—			$	1,524
Other	36		4		—				40
Marketable debt securities:
Corporate bonds	294		18		(2		)		310
U.S. Treasury securities and agency debentures	460		24		(1		)		483
State and municipal	237		18		—				255
Other	29		1		(1		)		29
Cost method investments	113		—		—				113
Cash equivalents and other(2)	45		—		—				45
Total	$	2,361	$	442	$	(4	)	(3)	$	2,799
December 31, 2010
Marketable equity securities:
U.S.:
Large Cap	$	1,161	$	515	$	—			$	1,676
Other	39		11		—				50
Marketable debt securities:
Corporate bonds	310		18		(1		)		327
U.S. Treasury securities and agency debentures	380		12		(1		)		391
State and municipal	244		7		(4		)		247
Other	19		—		—				19
Cost method investments	108		—		—				108
Cash equivalents and other(2)	79		—		—				79
Total	$	2,340	$	563	$	(6	)	(3)	$	2,897

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

(2) Includes pending purchases of securities of $23 million and $43 million at September 30, 2011 and December 31, 2010, respectively.

(3) The fair value of securities in an unrealized loss position was $158 million and $252 million at September 30, 2011 and December 31, 2010, respectively.

Investments Classified by Contractual Maturity Date

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2011 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	93
Due after one year through five years	304
Due after five years through ten years	316
Due after ten years	364
Total	$	1,077

Marketable Securities

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,
	2011		2010		2011		2010
(millions)
Proceeds from sales	$	465	$	398	$	1,404	$	1,538
Realized gains(1)	23		16		55		89
Realized losses(1)	62		4		82		58

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

Other Than Temporary Impairment Losses on Investment Securities

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	54		$	4		$	69		$	52
Losses recorded to decommissioning trust regulatory liability	(16		)	(1		)	(22		)	(17		)
Losses recognized in other comprehensive income (before taxes)	(2		)	—			(3		)	(2		)
Net impairment losses recognized in earnings	$	36		$	3		$	44		$	33

(1) Amount includes other-than-temporary impairment losses for debt securities of $3 million and $1 million for the three months ended September 30, 2011 and 2010, respectively, and $5 million and $4 million for the nine months ended September 30, 2011 and 2010, respectively.

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Comprehensive Income

9 Months Ended

Sep. 30, 2011

Comprehensive Income

Comprehensive Income

The following table presents Dominion’s total comprehensive income:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011				2010				2011				2010
(millions)
Net income including noncontrolling interests	$	396			$	579			$	1,219			$	2,522
Other comprehensive income (loss):
Net other comprehensive loss associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings	(94		)	(1)	(56		)		(172		)	(1)	(61		)
Other, net of tax	(76		)	(2)	70			(3)	3				86			(3)
Other comprehensive income (loss)	(170		)		14				(169		)		25
Comprehensive income including noncontrolling interests	226				593				1,050				2,547
Noncontrolling interests	4				4				12				12
Total comprehensive income attributable to Dominion	$	222			$	589			$	1,038			$	2,535

(1) Primarily reflects unfavorable changes in fair value due to a decrease in interest rates.

(2) Primarily reflects a net decrease in unrealized gains on investments held in nuclear decommissioning trusts.

(3) Primarily reflects a net increase in unrealized gains on investments held in nuclear decommissioning trusts.

The following table presents Virginia Power’s total comprehensive income:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Net income	$	297		$	380		$	816		$	742
Other comprehensive income (loss):
Net other comprehensive loss associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings	(3		)	(1		)	(4		)	(9		)
Other, net of tax	(8		)	6			(5		)	2
Other comprehensive income (loss)	(11		)	5			(9		)	(7		)
Total comprehensive income	$	286		$	385		$	807		$	735

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Derivatives and Hedge Accounting Activities (Narrative) (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Reclassification of gains from AOCI to earnings		$ 110
Reclassification of gains from AOCI to earnings, after-tax		67
Fair value of AOCI earnings, partially offset by subsequent changes	37	37
Fair value of AOCI earnings, partially offset by subsequent changes, after-tax	$ 23	$ 23

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Nature of Operations

9 Months Ended

Sep. 30, 2011

Nature of Operations

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.

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Ceiling Test

9 Months Ended

Sep. 30, 2011

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Ceiling Test

Ceiling Test

Dominion follows the full cost method of accounting for its gas and oil E&P activities, which subjects capitalized costs to a quarterly ceiling test using hedge-adjusted prices. Due to the April 2010 sale of substantially all of its Appalachian E&P operations, as of September 30, 2011, Dominion no longer has any significant gas and oil properties subject to the ceiling test calculation.

At March 31, 2010, Dominion recorded a ceiling test impairment charge of $21 million ($13 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income primarily due to a decline in hedge-adjusted prices reflecting the discontinuance of hedge accounting for certain cash flow hedges, as discussed in Note 3.

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Operating Revenue (Operating Revenue) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Electric sales:
Regulated	$ 2,136	$ 2,083	$ 5,594	$ 5,488
Nonregulated	915	1,072	2,650	2,857
Gas sales:
Regulated	25	25	208	209
Nonregulated	281	375	1,220	1,502
Gas transportation and storage	291	289	1,151	1,070
Other	155	106	378	325
Total operating revenue	$ 3,803	$ 3,950	$ 11,201	$ 11,451

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Derivatives and Hedge Accounting Activities (Tables)

9 Months Ended

Sep. 30, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Volumes of Derivative Activity

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)	257		67
Basis	891		405
Electricity (MWh):
Fixed price(1)	20,137,147		23,255,392
FTRs	78,993,580		779,328
Capacity (MW)	155,416		289,585
Liquids (gallons)(2)	138,516,000		281,064,000
Interest rate	$	1,600,000,000	$	2,690,000,000

(1) Includes options.

(2) Includes NGLs and oil.

Fair Value of Derivatives

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, 2011
ASSETS
Current Assets
Commodity	$	150	$	412	$	562
Interest rate	36		—		36
Total current derivative assets	186		412		598
Noncurrent Assets
Commodity	105		97		202
Interest rate	67		—		67
Total noncurrent derivative assets(1)	172		97		269
Total derivative assets	$	358	$	509	$	867
LIABILITIES
Current Liabilities
Commodity	$	186	$	476	$	662
Interest rate	124		7		131
Total current derivative liabilities(2)	310		483		793
Noncurrent Liabilities
Commodity	119		103		222
Interest rate	74		31		105
Total noncurrent derivative liabilities(3)	193		134		327
Total derivative liabilities	$	503	$	617	$	1,120
December 31, 2010
ASSETS
Current Assets
Commodity	$	291	$	425	$	716
Interest rate	23		—		23
Total current derivative assets	314		425		739
Noncurrent Assets
Commodity	44		83		127
Interest rate	31		—		31
Total noncurrent derivative assets(1)	75		83		158
Total derivative assets	$	389	$	508	$	897
LIABILITIES
Current Liabilities
Commodity	$	178	$	455	$	633
Total current derivative liabilities(2)	178		455		633
Noncurrent Liabilities
Commodity	86		106		192
Interest rate	5		—		5
Total noncurrent derivative liabilities(3)	91		106		197
Total derivative liabilities	$	269	$	561	$	830

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

(2) Current derivative liabilities are presented in other current liabilities in Dominion's Consolidated Balance Sheets.

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

Gains and Losses on Derivatives in Cash Flow Hedging Relationships

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, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	28
Purchased gas				(7		)
Electric fuel and other energy-related purchases				2
Total commodity	$	69		23			$	(1	)
Interest rate(3)	(204		)	(8		)	(76		)
Total	$	(135	)	$	15		$	(77	)
Three Months Ended September 30, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	88
Purchased gas				(6		)
Electric fuel and other energy-related purchases				4
Purchased electric capacity				1
Total commodity	$	(5	)	87			$	(6	)
Interest rate(3)	—			—			1
Foreign currency(4)	—			—			—
Total	$	(5	)	$	87		$	(5	)
Nine Months Ended September 30, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	88
Purchased gas				(61		)
Electric fuel and other energy-related purchases				4
Purchased electric capacity				1
Total commodity	$	(24	)	32			$	(10	)
Interest rate(3)	(236		)	(8		)	(76		)
Total	$	(260	)	$	24		$	(86	)
Nine Months Ended September 30, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	383
Purchased gas				(122		)
Electric fuel and other energy-related purchases				(4		)
Purchased electric capacity				3
Total commodity	$	277		260			$	(17	)
Interest rate(3)	(3		)	109			(23		)
Foreign currency(4)	—			1			(2		)
Total	$	274		$	370		$	(42	)

(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.

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

Schedule of Derivatives not Designated as Hedging Instruments

	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	2011			2010			2011			2010
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	15		$	45		$	56		$	71
Purchased gas	(10		)	(13		)	(28		)	(42		)
Electric fuel and other energy-related purchases	(8		)	23			(16		)	48
Interest rate(2)	(4		)	—			(4		)	(37		)
Total	$	(7	)	$	55		$	8		$	40

(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.

Cash Flow Hedge Gain Loss To Be Reclassified Within Twelve Months After Tax [Table Text Block]

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, 2011:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(19	)	$	(7	)	39 months
Electricity	38			21			51 months
NGLs	(39		)	(24		)	39 months
Other	6			1			44 months
Interest rate	(107		)	(5		)	375 months
Total	$	(121	)	$	(14	)

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Investments (Narrative) (Details) (USD $) In Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Categories of Investments, Marketable Securities, Trading Securities [Member]	Dec. 31, 2010 Categories of Investments, Marketable Securities, Trading Securities [Member]	Sep. 30, 2011 Categories of Investments, Cost-method Investments [Member]	Dec. 31, 2010 Categories of Investments, Cost-method Investments [Member]
Investments held in our rabbi trusts				$ 89	$ 93	$ 17	$ 18
Net unrealized gains (losses) on trading securities	$ 5	$ 1	$ 1

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Investments (Fair Value of our Marketable Debt Securities by Contractual Maturity) (Details) (USD $) In Millions	Sep. 30, 2011
Investments, Debt and Equity Securities [Abstract]
Due in one year or less	$ 93
Due after one year through five years	304
Due after five years through ten years	316
Due after ten years	364
Total	$ 1,077

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Fair Value Measurements (Financial Instruments' Carrying Amounts and Fair Values) (Details) (USD $) In Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2011		Dec. 31, 2010
Junior subordinated notes payable to affiliates	$ 268		$ 268	[1]
Enhanced junior subordinated notes	1,467		1,467	[1]
Subsidiary preferred stock	257		257	[1]
Valuation of certain fair value hedges	103		49
Issuance expenses of subsidiary preferred stock	2		2
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Long-term debt, including securities due within one year	16,745	[2]	14,520	[2]
Junior subordinated notes payable to affiliates	268		268
Enhanced junior subordinated notes	1,467		1,467
Subsidiary preferred stock	257	[3]	257	[3]
Estimate of Fair Value, Fair Value Disclosure [Member]
Long-term debt, including securities due within one year	19,381	[2],[4]	16,112	[2],[4]
Junior subordinated notes payable to affiliates	275	[4]	261	[4]
Enhanced junior subordinated notes	1,539	[4]	1,560	[4]
Subsidiary preferred stock	$ 262	[3],[4]	$ 249	[3],[4]

[1] Dominion’s Consolidated Balance Sheet at December 31, 2010 has been derived from the audited Consolidated Financial Statements at that date.

[2] Includes amounts which represent the unamortized discount and premium. At September 30, 2011 and December 31, 2010, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt of approximately $103 million and $49 million, respectively

[3] Includes issuance expenses of $2 million at September 30, 2011 and December 31, 2010.

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

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Variable Interest Entities (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Payment for electric capacity	$ 109,000,000	$ 116,000,000	$ 344,000,000	$ 333,000,000
Shared Services Purchased	100,000,000	104,000,000	292,000,000	352,000,000
Option Price To Purchase Generating Facility At End Of Lease			898,000,000
Percentage Of Appraised Value In Excess Of Construction Cost Added To Purchase Price Of Generating Facility			51.00%
Amount Of Property Plant And Equipment Expected To Be Recorded From Consolidation	1,000,000,000
Amount Of Debt Expected To Be Recorded From Consolidation	900,000,000
Amount Of Non Controlling Interest Expected To Be Recorded From Consolidation	100,000,000
Virginia Power [Member]
Aggregate generation capacity from long-term power and capacity contracts (MW)			870
Contracts expiry date start range			2015
Contract expiry date end range			2021
Remaining purchase commitments			1,400,000,000
Payment for electric capacity	52,000,000	53,000,000	156,000,000	160,000,000
Payment for electric energy	$ 38,000,000	$ 46,000,000	$ 103,000,000	$ 120,000,000

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Operating Revenue

9 Months Ended

Sep. 30, 2011

Operating Revenue

Operating Revenue

The Companies’ operating revenue consists of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions)
Dominion
Electric sales:
Regulated	$	2,136	$	2,083	$	5,594	$	5,488
Nonregulated	915		1,072		2,650		2,857
Gas sales:
Regulated	25		25		208		209
Nonregulated	281		375		1,220		1,502
Gas transportation and storage	291		289		1,151		1,070
Other	155		106		378		325
Total operating revenue	$	3,803	$	3,950	$	11,201	$	11,451
Virginia Power
Regulated electric sales	$	2,136	$	2,083	$	5,594	$	5,488
Other	41		28		97		73
Total operating revenue	$	2,177	$	2,111	$	5,691	$	5,561

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Income Taxes (Reconciliation of Income Taxes at the U.S. Statutory Federal Rate as Compared to the Income Tax Expense Recorded in Our Consolidated Statements of Income) (Details)	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Income Tax Disclosure [Abstract]
U.S. statutory rate	35.00%	35.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.60%	4.50%
Legislative changes	0.00%	1.20%
Other, net	(1.40%)	(0.40%)
Effective tax rate	37.20%	40.30%

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Earnings Per Share Computation

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions, except EPS)
Net income attributable to Dominion	$	392	$	575	$	1,207	$	2,510
Average shares of common stock outstanding – Basic	569.4		585.0		574.2		591.7
Net effect of potentially dilutive securities(1)	1.8		1.4		1.4		1.1
Average shares of common stock outstanding – Diluted	571.2		586.4		575.6		592.8
Earnings Per Common Share – Basic	$	0.69	$	0.98	$	2.10	$	4.24
Earnings Per Common Share – Diluted	$	0.69	$	0.98	$	2.10	$	4.23

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

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Significant Financing Transactions - (Commercial Paper, Bank Loans and Letters of Credit Outstanding) (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
Facility Limit	$ 3,500
Outstanding Commercial Paper	783
Outstanding Letters of Credit	127
Facility Capacity Available	2,590
Credit Facility, to support letters of credit	1,500
Credit Facility 1.5 Billion [Member] | Three Year Joint Revolving Credit Facility [Member}
Facility Limit	3,000	[1]
Outstanding Commercial Paper	783	[1]
Outstanding Letters of Credit	0	[1]
Facility Capacity Available	2,217	[1]
Credit facility initiation date	September 2010
Credit facility termination date	September 2016
Three Year Joint Revolving Credit Facility [Member}
Facility Limit	500	[2]
Outstanding Commercial Paper	0	[2]
Outstanding Letters of Credit	127	[2]
Facility Capacity Available	$ 373	[2]
Credit facility initiation date	September 2010
Credit facility termination date	September 2016

[1] This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. 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] This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

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Investments (Recorded Other-Than-Temporary Impairment Losses on Investments) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Investments, Debt and Equity Securities [Abstract]
Total other-than-temporary impairment losses	$ 54	[1]	$ 4	[1]	$ 69	[1]	$ 52	[1]
Losses recorded to decommissioning trust regulatory liability	(16)		(1)		(22)		(17)
Losses recognized in other comprehensive income (before taxes)	(2)		0		(3)		(2)
Net impairment losses recognized in earnings	36		3		44		33
Other-than-temporary impairment losses for debt securities	$ 3		$ 1		$ 5		$ 4

[1] Amount includes other-than-temporary impairment losses for debt securities of $3 million and $1 million for the three months ended September 30, 2011 and 2010, respectively, and $5 million and $4 million for the nine months ended September 30, 2011 and 2010, respectively.

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Significant Financing Transactions (Tables)

9 Months Ended

Sep. 30, 2011

Securities Financing Transactions Disclosures [Abstract]

Schedule of Line of Credit Facilities

At September 30, 2011, Dominion’s commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:

	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility(1)	$	3,000	$	783	$	—	$	2,217
Joint revolving credit facility(2)	500		—		127		373
Total	$	3,500	$	783	$	127	$	2,590

(1) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. 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) This credit facility was entered into in September 2010 with an original maturity date of September 2013. Effective October 1, 2011, pricing was amended and the maturity date was extended to September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

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Income Taxes (Narrative) (Details) (USD $) In Millions		1 Months Ended
	Sep. 30, 2011	Oct. 31, 2011 Tax Refund Claim [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound	$ 60
Unrecognized Tax Benefits, Period Increase (Decrease)		$ 96

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value Disclosures [Abstract]

Fair Value, by Balance Sheet Grouping

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, 2011
Assets
Derivatives:
Commodity	$	34	$	623	$	107	$	764
Interest rate	—		103		—		103
Investments(1):
Equity securities:
U.S.:
Large cap	1,551		—		—		1,551
Other	45		—		—		45
Non-U.S.:
Large cap	11		—		—		11
Fixed Income:
Corporate debt instruments	—		310		—		310
U.S. Treasury securities and agency debentures	309		175		—		484
State and municipal	—		296		—		296
Other	—		29		—		29
Cash equivalents and other	1		69		—		70
Restricted cash equivalents	—		204		—		204
Total assets	$	1,951	$	1,809	$	107	$	3,867
Liabilities
Derivatives:
Commodity	$	7	$	728	$	149	$	884
Interest Rate	—		236		—		236
Total liabilities	$	7	$	964	$	149	$	1,120
At December 31, 2010
Assets
Derivatives:
Commodity	$	62	$	734	$	47	$	843
Interest rate	—		54		—		54
Investments(1):
Equity securities:
U.S.:
Large cap	1,709		—		—		1,709
Other	56		—		—		56
Non-U.S.:
Large cap	12		—		—		12
Fixed Income:
Corporate debt instruments	—		327		—		327
U.S. Treasury securities and agency debentures	228		165		—		393
State and municipal	—		286		—		286
Other	—		19		—		19
Cash equivalents and other	25		97		—		122
Restricted cash equivalents	—		400		—		400
Total assets	$	2,092	$	2,082	$	47	$	4,221
Liabilities
Derivatives:
Commodity	$	12	$	716	$	97	$	825
Interest rate	—		5		—		5
Total liabilities	$	12	$	721	$	97	$	830

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

Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

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,
	2011			2010			2011			2010
(millions)
Beginning balance	$	(122	)	$	32		$	(50	)	$	(66	)
Total realized and unrealized gains (losses):
Included in earnings	(16		)	27			(24		)	40
Included in other comprehensive income (loss)	75			(65		)	16			20
Included in regulatory assets/liabilities	(3		)	(13		)	(35		)	1
Settlements	24			(23		)	47			(41		)
Transfers out of Level 3	—			25			4			29
Ending balance	$	(42	)	$	(17	)	$	(42	)	$	(17	)
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	$	7		$	4		$	29		$	(3	)

Fair Value, Unobservable Inputs, Gain (Loss) Included In Earnings

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

	Operating revenue			Electric fuel and other energy-related purchases			Purchased  gas			Total
(millions)
Three Months Ended September 30, 2011
Total gains (losses) included in earnings	$	(8	)	$	(8	)	$	—		$	(16	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date	7			—			—			7
Three Months Ended September 30, 2010
Total gains (losses) included in earnings	$	5		$	22		$	—		$	27
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	4			—			—			4
Nine Months Ended September 30, 2011
Total gains (losses) included in earnings	$	(8	)	$	(16	)	$	—		$	(24	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date	29			—			—			29
Nine Months Ended September 30, 2010
Total gains (losses) included in earnings	$	(5	)	$	49		$	(4	)	$	40
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	(3		)	—			—			(3		)

Cost and Fair Value of Financial Instruments Disclosure

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, 2011				December 31, 2010
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	16,745	$	19,381	$	14,520	$	16,112
Junior subordinated notes payable to affiliates	268		275		268		261
Enhanced junior subordinated notes	1,467		1,539		1,467		1,560
Subsidiary preferred stock(3)	257		262		257		249
Virginia Power
Long-term debt, including securities due within one year(2)	$	6,868	$	8,233	$	6,717	$	7,489
Preferred stock(3)	257		262		257		249

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

(2) Includes amounts which represent the unamortized discount and premium. At September 30, 2011 and December 31, 2010, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt of approximately $103 million and $49 million, respectively.

(3) Includes issuance expenses of $2 million at September 30, 2011 and December 31, 2010.

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Variable Interest Entities

9 Months Ended

Sep. 30, 2011

Variable Interest Entities

Variable Interest Entities

As discussed in Note 16 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2010, 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 $1.4 billion as of September 30, 2011. Virginia Power paid $52 million and $53 million for electric capacity and $38 million and $46 million for electric energy to these entities in the three months ended September 30, 2011 and 2010, respectively. Virginia Power paid $156 million and $160 million for electric capacity and $103 million and $120 million for electric energy to these entities in the nine months ended September 30, 2011 and 2010, respectively.

Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $100 million and $104 million for the three months ended September 30, 2011 and 2010, respectively, and $292 million and $352 million for the nine months ended September 30, 2011 and 2010, 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.

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Derivatives and Hedge Accounting Activities (Gains and Losses on Derivatives in Cash Flow Hedging Relationships) (Details) (Cash Flow Hedges [Member], USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	$ (135)	[1]	$ (5)	[1]	$ (260)	[1]	$ 274	[1]
Amount of Gain (Loss) Reclassified from AOCI to Income	15		87		24		370
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	(77)	[2]	(5)	[2]	(86)	[2]	(42)	[2]
Interest Rate Contract [Member]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	(204)	[1],[3]	0	[1],[3]	(236)	[1],[3]	(3)	[1],[3]
Amount of Gain (Loss) Reclassified from AOCI to Income	(8)	[3]	0	[3]	(8)	[3]	109	[3]
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	(76)	[2],[3]	1	[2],[3]	(76)	[2],[3]	(23)	[2],[3]
Commodity Contract [Member]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	69	[1]	(5)	[1]	(24)	[1]	277	[1]
Amount of Gain (Loss) Reclassified from AOCI to Income	23		87		32		260
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	(1)	[2]	(6)	[2]	(10)	[2]	(17)	[2]
Commodity Contract [Member] | Operating Revenue [Member]
Amount of Gain (Loss) Reclassified from AOCI to Income	28		88		88		383
Commodity Contract [Member] | Electric Fuel and Other Energy-Related Purchases [Member]
Amount of Gain (Loss) Reclassified from AOCI to Income	2		4		4		(4)
Commodity Contract [Member] | Gas Purchases [Member]
Amount of Gain (Loss) Reclassified from AOCI to Income	(7)		(6)		(61)		(122)
Commodity Contract [Member] | Electric Capacity Purchases [Member]
Amount of Gain (Loss) Reclassified from AOCI to Income			1		1		3
Foreign Currency [Member]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)			0	[1],[4]			0	[1],[4]
Amount of Gain (Loss) Reclassified from AOCI to Income			0	[4]			1	[4]
Increase (Decrease) in Derivatives Subject to Regulatory Treatment			$ 0	[2],[4]			$ (2)	[2],[4]

[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.

[4] Amounts recorded in Dominion’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.

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Investments (Selected Information Regarding Marketable Equity and Debt Securities) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Available-for-sale securities:
Proceeds from sales	$ 465		$ 398		$ 1,404		$ 1,538
Realized gains	23	[1]	16	[1]	55	[1]	89	[1]
Realized losses	$ 62	[1]	$ 4	[1]	$ 82	[1]	$ 58	[1]

[1] Includes realized gains or losses recorded to the decommissioning trust regulatory liability.

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Income Taxes

9 Months Ended

Sep. 30, 2011

Income Taxes

Income Taxes

Continuing Operations

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

	Dominion				Virginia Power
Nine Months Ended September 30,	2011		2010		2011		2010
U.S. statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.6		4.5		3.9		3.9
Legislative changes	—		1.2		—		1.3
Other, net	(1.4	)	(0.4	)	(0.5	)	(1.3	)
Effective tax rate	37.2	%	40.3	%	38.4	%	38.9	%

Dominion's and Virginia Power's effective tax rates in 2010 reflect the reduction of deferred tax assets resulting from the enactment of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act of 2010 which eliminated the employer's deduction, beginning in 2013, for that portion of its retiree prescription drug coverage cost that is being reimbursed by the Medicare Part D subsidy. In addition, Dominion's effective tax rate in 2010 reflects higher state income taxes due to the sale of its Appalachian E&P operations.

See Note 6 to the Consolidated Financial Statements in Dominion's and Virginia Power's Annual Report on Form 10-K for the year ended December 31, 2010, for a discussion of the Companies' unrecognized tax benefits. During the nine months ended September 30, 2011, Dominion's and Virginia Power's unrecognized tax benefits changed as follows:

	Dominion			Virginia Power
(millions)
Balance at January 1, 2011	$	307		$	117
Increases - prior period positions	24			17
Decreases - prior period positions	(53		)	(33		)
Current period positions	41			23
Balance at September 30, 2011	$	319		$	124

With the expiration of statutes of limitations, completion of audits and possible settlements with tax authorities, it is reasonably possible that unrecognized tax benefits could decrease during the next 12 months by up to $60 million for Dominion and up to $30 million for Virginia Power. In addition, based on Dominion's decision in October 2011 to file tax refund claims involving uncertainty in the reporting of asset dispositions, unrecognized tax benefits increased by $96 million.

Discontinued Operations

Income tax expense in 2010 for Dominion's discontinued operations primarily reflects the impact of goodwill written off in the sale of Peoples that is not deductible for tax purposes and the reversal of deferred taxes for which the benefit was offset by the reversal of income tax-related regulatory assets.

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Credit Risk

9 Months Ended

Sep. 30, 2011

Credit Risk

Credit Risk

Dominion’s and Virginia Power’s accounting policies for credit risk are discussed in Note 24 to the Consolidated Financial Statements in their Annual Report on Form 10-K for the year ended December 31, 2010.

At September 30, 2011, Dominion's gross credit exposure totaled $364 million. After the application of collateral, credit exposure is unchanged. Of this amount, investment grade counterparties, including those internally rated, represented 79%. One counterparty exposure represents 10% of Dominion's total exposure and is a large financial institution rated investment grade.

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, 2011 and December 31, 2010, Dominion would have been required to post an additional $66 million and $88 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion had posted $81 million in collateral, including $53 million of letters of credit, at September 30, 2011 and $54 million in collateral, including $19 million of letters of credit, at December 31, 2010, 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, 2011 and December 31, 2010 was $209 million and $210 million, respectively, which does not include the impact of any offsetting asset positions. See Note 10 for further information about derivative instruments.

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Significant Financing Transactions - (Narrative) (Details) (USD $)	9 Months Ended					9 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended					9 Months Ended		9 Months Ended			9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Aug. 31, 2011	Dec. 31, 2010 Virginia Power [Member]	Sep. 30, 2009 Virginia Power [Member]	Sep. 30, 2011 Virginia Power [Member] Solid Waste Disposal Revenue Bonds Series A [Member]	Sep. 30, 2009 Virginia Power [Member] Solid Waste Disposal Revenue Bonds Series A [Member]	Sep. 30, 2011 Loans Payable [Member] Senior Notes 4.45 Percent Due 2021 [Member]	Mar. 31, 2011 Loans Payable [Member] Senior Notes 4.45 Percent Due 2021 [Member]	Sep. 30, 2011 Loans Payable [Member] Senior Notes 1.80 Percent Due 2014 [Member]	Mar. 31, 2011 Loans Payable [Member] Senior Notes 1.80 Percent Due 2014 [Member]	Sep. 30, 2011 Convertible Debt [Member] days	Sep. 30, 2011 Maximum [Member]	Sep. 30, 2011 Minimum [Member]	Sep. 30, 2011 Senior Notes 4 Point 9 Percent Due In 2041 [Member]	Aug. 31, 2011 Senior Notes 4 Point 9 Percent Due In 2041 [Member]	Sep. 30, 2011 Senior Notes 1 Point 95 Percent Due In 2016 [Member]	Aug. 31, 2011 Senior Notes 1 Point 95 Percent Due In 2016 [Member]	Sep. 30, 2011 Massachusetts Development Finance Agency Recovery Zone Facility Bonds Series 2010 A [Member]	Dec. 31, 2010 Massachusetts Development Finance Agency Recovery Zone Facility Bonds Series 2010 A [Member]	Dec. 31, 2010 Solid Waste Disposal Revenue Bonds Series 2010 B [Member]	Sep. 30, 2011 Solid Waste Disposal Revenue Bonds Series A [Member]
Issuance of long-term debt				$ 100,000,000	$ 60,000,000		$ 160,000,000		$ 500,000,000		$ 400,000,000					$ 500,000,000		$ 450,000,000		$ 160,000,000	$ 75,000,000
Debt instrument, interest rate			2.25%					4.45%		1.80%						4.90%		1.95%
Debt maturity	2041					2040		2021		2014					2041		2016
Duration Of Coupon Rate																			5 years			5 years
Contingent convertible senior notes												165,000,000
Conversion rate, shares of common stock per $1,000 principal amount of senior notes												28.8178
Conversion rate, shares of common stock per $1,000 principal amount of senior notes, conversion price												$ 34.70
Principal amount of senior notes												1,000
Common stock, shares issued	1,000,000
Common stock, cash proceeds	37,000,000	66,000,000
Common Stock Expected To Be Repurchased With Tax Savings													700,000,000	600,000,000
Repurchase of common stock	601,000,000	900,000,000
Repurchase of common stock, shares	13,000,000
Conversion share price unmet	$ 46.37
Minimum consecutive trading days												20
Maximum consecutive trading days												30
Debt Conversion, Converted Instrument, Amount												$ 37,000,000

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Regulatory Matters (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Revenue Increase For Fuel	$ 37
Previously Deferred Fuel Costs	14
Ellisburg To Craigs Dekatherms Per Day Capacity	150,000
Dekatherms Per Day Northeast Expansion Project Is Expected To Provide	200,000
Expected Cost Of Northeast Expansion Project	100
Virginia Power [Member]
Basis Points Representing Allowed Range Of ROE	50
ROE Established In Virginia Settlement Approval Order	11.90%
ROE During 2009 And 2010 Test Years If Virginia Commission Accepts Virginia Commission Staff	14.11%
Total credit to customers if Virginia Commission accepts Virginia Commission staff accounting adjustments	143
ROE Virginia Power Believes It Earned During 2009 And 2010 Test Years	12.10%
ROE Virginia Power Is Requesting For 2011 And 2012	12.50%
Basis Points Performance Incentive As Provided For By Regulation Act	100
Virginia Commission Staff Recommended Prospective ROE	10.67%
Virginia Commission Staff RPS Performance Basis Points Incentive	50
Riders C1 and C2 Filing Placeholder ROE	12.50%
Virginia Power [Member] | Virginia Regulation [Member]
Increase Over Approved Revenue Requirement For May 1 2011 Through April 30 2012	68
Amount To Recover Projected Lost Revenues Associated With Energy Efficiency Programs	26
Virginia Powers Portion Of Mt Storm To Doubs Line Rebuild	350
Virginia Power [Member] | Virginia Regulation [Member] | Rider C1 and C2 [Member]
Proposed revenue requirement under Rider to go into effect April 1, 2011 for the rate year ending March 31, 2012	86
Virginia Regulation [Member]
Expected Cost Of Ellisburg To Craigs Project	46
Ohio Regulation [Member]
Current Annual PIR Capital Investment	120
Proposed Annual PIR Captial Investment	160
East Ohio PIR Program Revenue Requirement	$ 37

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Ceiling Test (Details) (USD $) In Millions	3 Months Ended
	Mar. 31, 2011
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Ceiling test impairment charge, before tax	$ 21
Ceiling test impairment charge, after tax	$ 13

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Employee Benefit Plans (Narrative) (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
Compensation and Retirement Disclosure [Abstract]
Dominion contribution	$ 0
Expected contribution to voluntary employees' beneficiary association	$ 18

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Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2011

Stockholders' Equity Note [Abstract]

Comprehensive Income

The following table presents Dominion’s total comprehensive income:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011				2010				2011				2010
(millions)
Net income including noncontrolling interests	$	396			$	579			$	1,219			$	2,522
Other comprehensive income (loss):
Net other comprehensive loss associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings	(94		)	(1)	(56		)		(172		)	(1)	(61		)
Other, net of tax	(76		)	(2)	70			(3)	3				86			(3)
Other comprehensive income (loss)	(170		)		14				(169		)		25
Comprehensive income including noncontrolling interests	226				593				1,050				2,547
Noncontrolling interests	4				4				12				12
Total comprehensive income attributable to Dominion	$	222			$	589			$	1,038			$	2,535

(1) Primarily reflects unfavorable changes in fair value due to a decrease in interest rates.

(2) Primarily reflects a net decrease in unrealized gains on investments held in nuclear decommissioning trusts.

(3) Primarily reflects a net increase in unrealized gains on investments held in nuclear decommissioning trusts.

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Consolidated Statements of Cash Flows (USD $) In Millions	9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010
Operating Activities
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 1,219		$ 2,522
Net Income Including Noncontrolling Interest	1,207		2,510
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Gain from sale of Appalachian E&P operations	0		(2,467)
Loss from sale of Peoples	0		113
Changes (payments) related to workforce reduction program	(93)		261
Impairment of merchant generation facility	55		163
Depreciation, depletion and amortization (including nuclear fuel)	951		946
Deferred income taxes and investment tax credits	643		310
Contribution to employee pension plans	0		(250)
Rate refunds	(64)		(413)
Other adjustments	(3)		(20)
Changes in:
Accounts receivable	527		360
Inventories	(162)		(23)
Deferred fuel expenses	(60)		(147)
Prepayments	(53)		274
Accounts payable	(419)		(51)
Accrued interest, payroll and taxes	(201)		270
Margin deposit assets and liabilities	(92)		(23)
Other operating assets and liabilities	150		59
Net cash provided by operating activities	2,398		1,884
Investing Activities
Plant construction and other property additions	2,616		2,509
Proceeds from sale of securities	1,404		1,938
Purchases of securities	(1,459)		(2,470)
Restricted cash equivalents	(196)		0
Other	(111)		(75)
Net cash provided by (used in) investing activities	(2,364)		1,225
Financing Activities
Repayment of short-term debt, net	(602)		(1,195)
Issuance and remarketing of long-term debt	2,245		550
Repayment of long-term debt	(74)		(414)
Issuance of common stock	37		66
Repurchase of common stock	(601)		(900)
Common dividend payments	(848)		(810)
Preferred dividend payments	(12)		(12)
Other	(29)		2
Net cash provided by (used in) financing activities	116		(2,713)
Increase in cash and cash equivalents	150		396
Cash and cash equivalents at beginning of period	62	[1]	50
Cash and cash equivalents at end of period	212		446
Significant noncash investing activities:
Accrued capital expenditures	237		192
Appalachian E And P [Member]
Investing Activities
Proceeds from the sale of business	0		3,450
Peoples [Member]
Investing Activities
Proceeds from the sale of business	0		741
Virginia Electric and Power Company [Member]
Operating Activities
Net Income Including Noncontrolling Interest	816		742
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Changes (payments) related to workforce reduction program	(41)		98
Depreciation, depletion and amortization (including nuclear fuel)	625		584
Deferred income taxes and investment tax credits	449		399
Contribution to employee pension plans	0		(119)
Rate refunds	(64)		(413)
Other adjustments	9		(32)
Changes in:
Accounts receivable	14		(38)
Affiliated accounts receivable and payable	(7)		(1)
Inventories	(135)		10
Deferred fuel expenses	(58)		(126)
Prepayments	(6)		(62)
Accounts payable	6		80
Accrued interest, payroll and taxes	72		66
Other operating assets and liabilities	3		48
Net cash provided by operating activities	1,697		1,238
Investing Activities
Plant construction and other property additions	(1,392)		(1,579)
Purchases of nuclear fuel	(169)		(114)
Proceeds from sale of securities	838		959
Purchases of securities	850		976
Restricted cash equivalents	131		0
Other	11		2
Net cash provided by (used in) investing activities	(1,431)		(1,708)
Financing Activities
Repayment of short-term debt, net	(50)		(342)
Issuance of affiliated current borrowings, net	112		897
Issuance and remarketing of long-term debt	160		300
Repayment of long-term debt	(10)		(11)
Common dividend payments	(448)		(360)
Preferred dividend payments	(12)		(12)
Other	1		1
Net cash provided by (used in) financing activities	(247)		473
Increase in cash and cash equivalents	19		3
Cash and cash equivalents at beginning of period	5	[2]	19
Cash and cash equivalents at end of period	24		22
Significant noncash investing activities:
Accrued capital expenditures	86		114
Settlement of debt and issuance of common stock to Dominion	$ 0		$ 636

[1] Dominion’s Consolidated Balance Sheet at December 31, 2010 has been derived from the audited Consolidated Financial Statements at that date.

[2] Virginia Power’s Consolidated Balance Sheet at December 31, 2010 has been derived from the audited Consolidated Financial Statements at that date.

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Related Party Transactions

9 Months Ended

Sep. 30, 2011

Related Party Transactions

Related Party Transactions

Virginia Power engages in related-party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power's receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power is included in Dominion's consolidated federal income tax return and participates in certain Dominion benefit plans. A discussion of significant related party transactions follows.

Transactions with Affiliates

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

DRS provides 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,
	2011		2010		2011		2010
(millions)
Commodity purchases from affiliates	$	150	$	150	$	302	$	306
Services provided by affiliates	101		106		294		355

Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. Virginia Power's outstanding borrowings, net of repayments, under the Dominion money pool for its nonregulated subsidiaries totaled $166 million and $24 million as of September 30, 2011 and December 31, 2010, respectively. Virginia Power's short-term demand note borrowings from Dominion were $49 million and $79 million as of September 30, 2011 and December 31, 2010. Virginia Power's interest charges related to its borrowings from Dominion were immaterial for the three and nine months ended September 30, 2011 and 2010.

In March, September and October 2010, Virginia Power issued 14,600, 6,700 and 8,900 shares of its common stock to Dominion for approximately $433 million, $203 million and $277 million, respectively. The proceeds were used to pay down short-term demand note borrowings from Dominion.

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Earnings Per Share (Narrative) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Earnings Per Share [Abstract]
Potentially dilutive securities not included in the calculation of diluted EPS because the exercise or purchase prices were greater than the average market price of our common shares	0	0	0	0

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Operating Segments

9 Months Ended

Sep. 30, 2011

Operating Segments

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	X
	LNG import and storage	X
	Producer services	X

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

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

In the nine months ended September 30, 2011, Dominion reported after-tax net expenses of $213 million for specific items in the Corporate and Other segment, with $217 million of these net expenses attributable to its operating segments. In the nine months ended September 30, 2010, Dominion reported after-tax net benefits of $905 million for specific items in the Corporate and Other segment, with $1.1 billion of these net benefits attributable to its operating segments.

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

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

• A $55 million ($39 million after-tax) impairment charge related to State Line, attributable to Dominion Generation;

• A $57 million ($34 million after-tax) charge related to the impairment of SO₂ emissions allowances not expected to be consumed due to CSAPR, attributable to Dominion Generation; and

• A $56 million ($32 million after-tax) loss from the operations of Kewaunee, attributable to Dominion Generation.  Kewaunee's results of operations have been reflected in the Corporate and Other segment due to Dominion's decision in the first quarter of 2011 to pursue the sale of Kewaunee.

The net benefits for specific items in 2010 primarily related to the impact of the following items:

• A $2.5 billion ($1.4 billion after-tax) benefit resulting from the gain on the sale of substantially all of Dominion's Appalachian E&P operations net of charges related to the divestiture, attributable to Dominion Energy; partially offset by

• A $338 million ($206 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program, attributable to:

• DVP ($67 million after-tax);

• Dominion Energy ($24 million after-tax); and

• Dominion Generation ($115 million after-tax);

• A $134 million ($147 million after-tax) loss from the discontinued operations of Peoples primarily reflecting a net loss on the sale, attributable to the Corporate and Other segment; and

• A $163 million ($95 million after-tax) impairment charge related to State Line, attributable to Dominion Generation.

The Corporate and Other Segment of Virginia Power primarily includes certain specific items that are not included in profit measures evaluated by executive management in assessing segment performance or allocating resources among the segments. In the nine months ended September 30, 2011 and 2010, Virginia Power reported after-tax net expenses of $126 million and $149 million, respectively, for specific items attributable to its operating segments in the Corporate and Other segment.

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

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

• A $43 million ($26 million after-tax) charge related to the impairment of SO₂ emissions allowances not expected to be consumed due to CSAPR, attributable to Dominion Generation.

The net expenses for specific items in 2010 primarily related to the impact of the following:

• A $202 million ($123 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program, attributable to:

• DVP ($63 million after-tax); and

• Dominion Generation ($60 million after-tax).

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

	DVP		Dominion Generation		Dominion Energy		Corporate and Other			Adjustments/Eliminations			Consolidated Total
(millions)
Three Months Ended September 30,
2011
Total revenue from external customers	$	922	$	2,142	$	290	$	23		$	426		$	3,803
Intersegment revenue	21		114		341		149			(625		)	—
Total operating revenue	943		2,256		631		172			(199		)	3,803
Net income (loss) attributable to Dominion	125		394		95		(222		)	—			392
2010
Total revenue from external customers	$	907	$	2,312	$	367	$	(6	)	$	370		$	3,950
Intersegment revenue	16		114		339		172			(641		)	—
Total operating revenue	923		2,426		706		166			(271		)	3,950
Net income (loss) attributable to Dominion	107		487		92		(111		)	—			575
Nine Months Ended September 30,
2011
Total revenue from external customers	$	2,801	$	5,765	$	1,503	$	96		$	1,036		$	11,201
Intersegment revenue	134		271		843		443			(1,691		)	—
Total operating revenue	2,935		6,036		2,346		539			(655		)	11,201
Net income (loss) attributable to Dominion	389		886		368		(436		)	—			1,207
2010
Total revenue from external customers	$	2,697	$	6,121	$	1,667	$	28		$	938		$	11,451
Intersegment revenue	123		324		906		571			(1,924		)	—
Total operating revenue	2,820		6,445		2,573		599			(986		)	11,451
Loss from discontinued operations, net of tax	—		—		—		(147		)	—			(147		)
Net income attributable to Dominion	333		1,088		353		736			—			2,510

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

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

	DVP		Dominion Generation		Corporate and Other			Consolidated Total
(millions)
Three Months Ended September 30,
2011
Operating revenue	$	484	$	1,704	$	(11	)	$	2,177
Net income (loss)	127		289		(119		)	297
2010
Operating revenue	$	453	$	1,658	$	—		$	2,111
Net income (loss)	102		286		(8		)	380
Nine Months Ended September 30,
2011
Operating revenue	$	1,367	$	4,336	$	(12	)	$	5,691
Net income (loss)	342		598		(124		)	816
2010
Operating revenue	$	1,253	$	4,308	$	—		$	5,561
Net income (loss)	300		589		(147		)	742

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Operating Segments (Narrative) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Costs and Expenses	$ 2,970		$ 2,831		$ 8,680		$ 8,955
Loss from Catastrophes					121
Loss From Catastrophes Net Of Tax					74
Income (loss) from discontinued operations, after-tax	0	[1]	0	[1]	0	[1]	(147)	[1]
Before Tax Gain From Agreement To Sell Appalachian EP	0		0		0		2,467
After Tax Gain From Agreement To Sell Appalachian EP							1,400.0
Charge primarily reflecting severance pay and other benefits related to a workforce reduction program, before tax							338
Charge primarily reflecting severance pay and other benefits related to a workforce reduction program, after-tax							206
Impairment Of Emissions Allowances					57
Impairment Of Emissions Net Of Taxes					34
Operating Income (Loss)	(833)		(1,119)		(2,521)		(4,963)
Corporate and Other [Member]
After Tax Net Benefits Expenses Attributable To Operating Segments					217		1,100
Costs and Expenses					213		905
Dominion Virginia Power [Member]
Charge primarily reflecting severance pay and other benefits related to a workforce reduction program, after-tax							67
Dominion Energy [Member]
Charge primarily reflecting severance pay and other benefits related to a workforce reduction program, after-tax							24
Dominion Generation [Member]
Charge primarily reflecting severance pay and other benefits related to a workforce reduction program, after-tax							115
Impairment charges					55		163
Impairment charges, after-tax					39		95
Operating Income (Loss)					56
Operating Income Loss After Tax					32
Peoples [Member]
Benefit from gain on sale Dominion's Appalachian E&P operations, before tax							134
Benefit from gain on sale Dominion's Appalachian E&P operations, after-tax							$ 147

[1] Includes income tax expense of $13 million for the nine months ended September 30, 2010.

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Commitments and Contingencies (Subsidiary Guarantees) (Details) (USD $) In Millions	Sep. 30, 2011
Stated Limit	$ 5,041
Value	1,731	[1]
Third Party and Equity Method Investee [Member]
Stated Limit	54
Millstone Power Station [Member] | Nuclear Obligations [Member]
Stated Limit	150
Kewaunee Power Station [Member] | Nuclear Obligations [Member]
Stated Limit	60
Subsidiary Debt [Member]
Stated Limit	363	[2]
Value	363	[1],[2]
Commodity Transactions [Member]
Stated Limit	3,182	[3]
Value	429	[1],[3]
Capital Lease Obligations [Member]
Stated Limit	748	[4]
Value	748	[1],[4]
Nuclear Obligations [Member]
Stated Limit	231	[5]
Value	50	[1],[5]
Other [Member]
Stated Limit	517	[6]
Value	$ 141	[1],[6]

[1] )Represents the estimated portion of the guarantee's stated limit that is utilized as of September 30, 2011 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount

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

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

[4] )

[5] )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

[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

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Significant Accounting Policies

9 Months Ended

Sep. 30, 2011

Significant Accounting Policies

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, 2010 and their Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

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, 2011, their results of operations for the three and nine months ended September 30, 2011 and 2010 and their cash flows for the nine months ended September 30, 2011 and 2010. 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.

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 2010 Consolidated Financial Statements and Notes have been reclassified to conform to the 2011 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, shareholders’ equity or cash flows.

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

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Investments

9 Months Ended

Sep. 30, 2011

Investments

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 $89 million and $93 million at September 30, 2011 and December 31, 2010, respectively. Net unrealized losses on trading securities totaled $5 million and $1 million for the three and nine months ended September 30, 2011, respectively. Net unrealized losses on trading securities totaled $1 million for the nine months ended September 30, 2010. Cost-method investments held in Dominion’s rabbi trusts totaled $17 million and $18 million at September 30, 2011 and December 31, 2010, respectively.

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, 2011
Marketable equity securities
U.S.:
Large Cap	$	1,147	$	377	$	—			$	1,524
Other	36		4		—				40
Marketable debt securities:
Corporate bonds	294		18		(2		)		310
U.S. Treasury securities and agency debentures	460		24		(1		)		483
State and municipal	237		18		—				255
Other	29		1		(1		)		29
Cost method investments	113		—		—				113
Cash equivalents and other(2)	45		—		—				45
Total	$	2,361	$	442	$	(4	)	(3)	$	2,799
December 31, 2010
Marketable equity securities:
U.S.:
Large Cap	$	1,161	$	515	$	—			$	1,676
Other	39		11		—				50
Marketable debt securities:
Corporate bonds	310		18		(1		)		327
U.S. Treasury securities and agency debentures	380		12		(1		)		391
State and municipal	244		7		(4		)		247
Other	19		—		—				19
Cost method investments	108		—		—				108
Cash equivalents and other(2)	79		—		—				79
Total	$	2,340	$	563	$	(6	)	(3)	$	2,897

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

(2) Includes pending purchases of securities of $23 million and $43 million at September 30, 2011 and December 31, 2010, respectively.

(3) The fair value of securities in an unrealized loss position was $158 million and $252 million at September 30, 2011 and December 31, 2010, respectively.

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2011 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	93
Due after one year through five years	304
Due after five years through ten years	316
Due after ten years	364
Total	$	1,077

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,
	2011		2010		2011		2010
(millions)
Proceeds from sales	$	465	$	398	$	1,404	$	1,538
Realized gains(1)	23		16		55		89
Realized losses(1)	62		4		82		58

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	54		$	4		$	69		$	52
Losses recorded to decommissioning trust regulatory liability	(16		)	(1		)	(22		)	(17		)
Losses recognized in other comprehensive income (before taxes)	(2		)	—			(3		)	(2		)
Net impairment losses recognized in earnings	$	36		$	3		$	44		$	33

(1) Amount includes other-than-temporary impairment losses for debt securities of $3 million and $1 million for the three months ended September 30, 2011 and 2010, respectively, and $5 million and $4 million for the nine months ended September 30, 2011 and 2010, respectively.

Virginia Power

Decommissioning Trust Securities

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

	Amortized Cost		Total  Unrealized Gains(1)		Total  Unrealized Losses(1)				Fair Value
(millions)
September 30, 2011
Marketable equity securities:
U.S.:
Large Cap	$	459	$	154	$	—			$	613
Other	18		2		—				20
Marketable debt securities:
Corporate bonds	180		10		(1		)		189
U.S. Treasury securities and agency debentures	189		7		—				196
State and municipal	93		7		—				100
Other	22		1		(1		)		22
Cost method investments	113		—		—				113
Cash equivalents and other(2)	32		—		—				32
Total	$	1,106	$	181	$	(2	)	(3)	$	1,285
December 31, 2010
Marketable equity securities
U.S.:
Large Cap	$	469	$	207	$	—			$	676
Other	20		5		—				25
Marketable debt securities:
Corporate bonds	205		10		—				215
U.S. Treasury securities and agency debentures	141		2		—				143
State and municipal	103		1		(2		)		102
Other	15		—		—				15
Cost method investments	108		—		—				108
Cash equivalents and other(2)	35		—		—				35
Total	$	1,096	$	225	$	(2	)	(3)	$	1,319

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

(2) Includes pending purchases of securities of $14 million and $35 million at September 30, 2011 and December 31, 2010, respectively.

(3) The fair value of securities in an unrealized loss position was $101 million and $159 million at September 30, 2011 and December 31, 2010, respectively.

The fair value of Virginia Power’s debt securities at September 30, 2011, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	11
Due after one year through five years	164
Due after five years through ten years	199
Due after ten years	133
Total	$	507

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(millions)
Proceeds from sales	$	242	$	248	$	838	$	959
Realized gains(1)	10		6		21		43
Realized losses(1)	22		1		30		21

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	19		$	2		$	26		$	21
Losses recorded to decommissioning trust regulatory liability	(16		)	(1		)	(22		)	(17		)
Net impairment losses recognized in earnings	$	3		$	1		$	4		$	4

(1) Amount includes other-than-temporary impairment losses for debt securities of $2 million and $1 million for the three months ended September 30, 2011 and 2010, respectively, and $4 million and $2 million for the nine months ended September 30, 2011 and 2010, respectively.

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Derivatives and Hedge Accounting Activities (Fair Value of Derivatives) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Total Fair Value, Assets	$ 867		$ 897
Total Fair Value, Liabilities	1,120		830
Interest Rate Contract [Member] | Fair Value - Derivatives under Hedge Accounting [Member] | Current Assets [Member]
Total Fair Value, Assets	36		23
Interest Rate Contract [Member] | Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Assets [Member]
Total Fair Value, Assets	67		31
Interest Rate Contract [Member] | Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities [Member]
Total Fair Value, Liabilities	124
Interest Rate Contract [Member] | Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Liabilities [Member]
Total Fair Value, Liabilities	74		5
Commodity Contract [Member] | Fair Value - Derivatives under Hedge Accounting [Member] | Current Assets [Member]
Total Fair Value, Assets	150		291
Commodity Contract [Member] | Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Assets [Member]
Total Fair Value, Assets	105		44
Commodity Contract [Member] | Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities [Member]
Total Fair Value, Liabilities	186		178
Commodity Contract [Member] | Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Liabilities [Member]
Total Fair Value, Liabilities	119		86
Fair Value - Derivatives under Hedge Accounting [Member]
Total Fair Value, Assets	358		389
Total Fair Value, Liabilities	503		269
Fair Value - Derivatives under Hedge Accounting [Member] | Current Assets [Member]
Total Fair Value, Assets	186		314
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Assets [Member]
Total Fair Value, Assets	172	[1]	75	[1]
Fair Value - Derivatives under Hedge Accounting [Member] | Current Liabilities [Member]
Total Fair Value, Liabilities	310	[2]	178	[2]
Fair Value - Derivatives under Hedge Accounting [Member] | Noncurrent Liabilities [Member]
Total Fair Value, Liabilities	193	[3]	91	[3]
Interest Rate Contract [Member] | Fair Value - Derivatives not under Hedge Accounting [Member] | Current Assets [Member]
Total Fair Value, Assets	0		0
Interest Rate Contract [Member] | Fair Value - Derivatives not under Hedge Accounting [Member] | Noncurrent Assets [Member]
Total Fair Value, Assets	0		0
Interest Rate Contract [Member] | Fair Value - Derivatives not under Hedge Accounting [Member] | Current Liabilities [Member]
Total Fair Value, Liabilities	7
Interest Rate Contract [Member] | Fair Value - Derivatives not under Hedge Accounting [Member] | Noncurrent Liabilities [Member]
Total Fair Value, Liabilities	31		0
Commodity Contract [Member] | Fair Value - Derivatives not under Hedge Accounting [Member] | Current Assets [Member]
Total Fair Value, Assets	412		425
Commodity Contract [Member] | Fair Value - Derivatives not under Hedge Accounting [Member] | Noncurrent Assets [Member]
Total Fair Value, Assets	97		83
Commodity Contract [Member] | Fair Value - Derivatives not under Hedge Accounting [Member] | Current Liabilities [Member]
Total Fair Value, Liabilities	476		455
Commodity Contract [Member] | Fair Value - Derivatives not under Hedge Accounting [Member] | Noncurrent Liabilities [Member]
Total Fair Value, Liabilities	103		106
Fair Value - Derivatives not under Hedge Accounting [Member]
Total Fair Value, Assets	509		508
Total Fair Value, Liabilities	617		561
Fair Value - Derivatives not under Hedge Accounting [Member] | Current Assets [Member]
Total Fair Value, Assets	412		425
Fair Value - Derivatives not under Hedge Accounting [Member] | Noncurrent Assets [Member]
Total Fair Value, Assets	97	[1]	83	[1]
Fair Value - Derivatives not under Hedge Accounting [Member] | Current Liabilities [Member]
Total Fair Value, Liabilities	483	[2]	455	[2]
Fair Value - Derivatives not under Hedge Accounting [Member] | Noncurrent Liabilities [Member]
Total Fair Value, Liabilities	134	[3]	106	[3]
Interest Rate Contract [Member] | Current Assets [Member]
Total Fair Value, Assets	36		23
Commodity Contract [Member] | Current Assets [Member]
Total Fair Value, Assets	562		716
Current Assets [Member]
Total Fair Value, Assets	598		739
Interest Rate Contract [Member] | Noncurrent Assets [Member]
Total Fair Value, Assets	67		31
Commodity Contract [Member] | Noncurrent Assets [Member]
Total Fair Value, Assets	202		127
Noncurrent Assets [Member]
Total Fair Value, Assets	269	[1]	158	[1]
Interest Rate Contract [Member] | Current Liabilities [Member]
Total Fair Value, Liabilities	131
Commodity Contract [Member] | Current Liabilities [Member]
Total Fair Value, Liabilities	662		633
Current Liabilities [Member]
Total Fair Value, Liabilities	793	[2]	633	[2]
Interest Rate Contract [Member] | Noncurrent Liabilities [Member]
Total Fair Value, Liabilities	105		5
Commodity Contract [Member] | Noncurrent Liabilities [Member]
Total Fair Value, Liabilities	222		192
Noncurrent Liabilities [Member]
Total Fair Value, Liabilities	$ 327	[3]	$ 197	[3]

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

[2] Current derivative liabilities are presented in other current liabilities in Dominion's Consolidated Balance Sheets.

[3] Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheets.

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Investments (Marketable Equity and Debt Securities and Cash Equivalents (Classified as Available-for-sale) and Cost Method Investments in Decommissioning Trust Funds) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Available-for-sale Securities, Amortized Cost Basis, and Other Investments	$ 2,361		$ 2,340
Total Unrealized Gains	442	[1]	563	[1]
Total Unrealized Losses	(4)	[1],[2]	(6)	[1],[2]
Fair Value	2,799		2,897	[3]
Net assets related to pending sales and purchases of securities	23		43
Fair Value of securities in an unrealized loss position	158		252
Equity Securities [Member] | Large Cap [Member] | United States [Member]
Amortized Cost	1,147		1,161
Total Unrealized Gains	377	[1]	515	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	1,524		1,676
Equity Securities [Member] | Other Market [Member] | United States [Member]
Amortized Cost	36		39
Total Unrealized Gains	4	[1]	11	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	40		50
Corporate Debt Securities [Member]
Amortized Cost	294		310
Total Unrealized Gains	18	[1]	18	[1]
Total Unrealized Losses	(2)	[1]	(1)	[1]
Fair Value	310		327
U.S. Treasury Securities and Agency Debentures [Member]
Amortized Cost	460		380
Total Unrealized Gains	24	[1]	12	[1]
Total Unrealized Losses	(1)	[1]	(1)	[1]
Fair Value	483		391
State and Municipal [Member]
Amortized Cost	237		244
Total Unrealized Gains	18	[1]	7	[1]
Total Unrealized Losses	0	[1]	(4)	[1]
Fair Value	255		247
Other Debt Securities [Member]
Amortized Cost	29		19
Total Unrealized Gains	1	[1]	0	[1]
Total Unrealized Losses	(1)	[1]	0	[1]
Fair Value	29		19
Cost-method Investments [Member]
Amortized Cost	113		108
Fair Value	113		108
Cash Equivalents and Other Investment [Member]
Amortized Cost	45	[4]	79	[4]
Fair Value	$ 45	[4]	$ 79	[4]

[1] Included in AOCI and the decommissioning trust regulatory liability.

[2] The fair value of securities in an unrealized loss position was $158 million and $252 million at September 30, 2011 and December 31, 2010, respectively.

[3] Dominion’s Consolidated Balance Sheet at December 31, 2010 has been derived from the audited Consolidated Financial Statements at that date.

[4] Includes pending purchases of securities of $23 million and $43 million at September 30, 2011 and December 31, 2010, respectively.

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Credit Risk (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Gross credit exposure	$ 364
Additional collateral to be posted if the credit-related contingent features were triggered	66	88
Collateral already posted	81	54
Letters of credit included in the collateral posted	53	19
Fair value of all derivative instruments not fully collateralized	$ 209	$ 210
Investment Grade [Member] | Credit Concentration Risk [Member] | Internal Credit Rating [Member]
Concentration of credit risk	79.00%
Investment Grade [Member] | Counterparty, A [Member]
Concentration of credit risk	10.00%

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2011

Commitments and Contingencies Disclosure [Abstract]

Subsidiary Guarantees

ions.

At September 30, 2011, Dominion had issued the following subsidiary guarantees:

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	363	$	363
Commodity transactions(3)	3,182		429
Lease obligation for power generation facility(4)	748		748
Nuclear obligations(5)	231		50
Other(6)	517		141
Total	$	5,041	$	1,731

(1) Represents the estimated portion of the guarantee's stated limit that is utilized as of September 30, 2011 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

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

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

(4) Guarantee of a DEI subsidiary's leasing obligation for Fairless, including a residual value guarantee.

(5) 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.

(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 Ned

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

Commitments and Contingencies

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, 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. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss does 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

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.

Air

In July 2011, the EPA issued a final replacement rule for CAIR, called CSAPR, that requires 27 states to reduce power plant emissions that cross state lines. CSAPR establishes new SO₂ and NO_x emissions cap and trade programs that are completely independent of the current ARP. Specifically, CSAPR requires 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.

Prior to the issuance of CSAPR, Dominion and Virginia Power held $57 million and $43 million, respectively, of SO₂ emissions allowances obtained for ARP and CAIR compliance. Due to CSAPR's establishment of a new allowance program and the elimination of CAIR, Dominion and Virginia Power have more SO₂ emissions allowances than needed for ARP compliance, which resulted in the impairment of these allowances in the third quarter of 2011. See Note 9 for further details of the impairments.

With respect to Dominion's generation fleet, the impact of the rule is not expected to be material. However, a large number of petitions for review of CSAPR have been filed in federal court and it is anticipated that there will be significant litigation of this rule.  In addition, the EPA has proposed, but not yet finalized, changes to the rule.  Accordingly, future outcomes of litigation and/or final action to modify the rule could affect this assessment. 

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

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

Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The CAA authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. In addition to any such penalties that may be awarded, an adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures that cannot be determined at this time. Such expenditures could affect future results of operations, cash flows, and financial condition. Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.

In June 2010, the Conservation Law Foundation and Healthlink Inc. filed a Complaint in the District Court of Massachusetts against Dominion Energy New England, Inc. alleging that Salem Harbor units 1, 2, 3, and 4 have been and are in violation of visible emissions standards and monitoring requirements of the Massachusetts State Implementation Plan and the station's state and federal operating permits. Although Dominion cannot predict the outcome of this matter at this time, it is not expected to have a material effect on results of operations, financial condition and/or cash flows.

Water

In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. Currently, Dominion is constructing the cooling towers and estimates the total cost to install these cooling towers at approximately $600 million, with remaining expenditures of approximately $100 million included in its planned capital expenditures through 2012.

In October 2007, the VSWCB issued a renewed VPDES permit for North Anna. BREDL, and other persons, appealed the VSWCB's decision to the Richmond Circuit Court, challenging several permit provisions related to North Anna's discharge of cooling water. In February 2009, the court ruled that the VSWCB was required to regulate the thermal discharge from North Anna into the waste heat treatment facility. Virginia Power filed a motion for reconsideration with the court in February 2009, which was denied. The final order was issued by the court in September 2009. The court's order allows North Anna to continue to operate pursuant to the currently issued VPDES permit. In October 2009, Virginia Power filed a Notice of Appeal of the court's order with the Richmond Circuit Court, initiating the appeals process to the Virginia Court of Appeals. In June 2010, the Virginia Court of Appeals reversed the Richmond Circuit Court's September 2009 order. The Virginia Court of Appeals held that the lower court had applied the wrong standard of review, and that the VSWCB's determination not to regulate the station's thermal discharge into the waste heat treatment facility was lawful. In July 2010, BREDL and the other original appellants filed a petition for appeal to the Supreme Court of Virginia requesting that it review the Court of Appeals' decision. In December 2010, the Supreme Court of Virginia granted BREDL's petition. Briefing on the merits of the case was completed in February 2011.  The court has scheduled oral arguments for October 31, 2011. Dominion is currently unable to make an estimate of the potential financial statement impacts related to this matter. However, an adverse resolution could ultimately require significant capital expenditures which could have a material effect on Dominion's and Virginia Power's results of operations, financial condition and/or cash flows.

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, however, Dominion cannot currently predict the outcome of this evaluation. 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

In March 2011, the EPA issued a final rule identifying NHSMs that would be considered solid waste when burned in combustion units, as opposed to being legitimate fuels or ingredients. The rule's premise is that any combusted NHSM is a solid waste unless such material satisfies the rule's criteria for either a fuel or an ingredient. Sources that combust solid waste are considered solid waste incinerators rather than industrial or utility boilers and would have to comply with the EPA's more stringent emission standards for solid waste incinerators. Dominion and Virginia Power have several electric generating units that combust fuel materials that may be subject to the rule. Some units use a technology that combusts residual coal in fly ash to recover additional energy from unburned carbon. This technology also produces a final ash product that is marketable for beneficial reuse in cement production. Because of the uncertainty associated with the rule's potential applicability to this and other processes, in June 2011, Dominion filed a petition for review with the Court of Appeals for the District of Columbia Circuit challenging the final rule. In October 2011, the EPA announced that it would initiate additional rulemaking proceedings to revise the final rule. Although Dominion cannot predict the outcome of this matter at this time, it is not expected to have a material effect on results of operations, financial condition, and/or cash flows.

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

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

In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina.  Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. Virginia Power has until early November 2011 to respond to the EPA regarding its willingness 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 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. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the 17 former sites with which Dominion is associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program and Dominion has not yet estimated the future remediation costs. Due to the uncertainty surrounding these sites, Dominion is unable to make an estimate of the potential financial statement impacts related to these sites.

Climate Change Legislation and Regulation

Massachusetts, Rhode Island and Connecticut, among other states, have joined the 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 2011 and possibly continuing through 2012, RGGI will undergo a program review which could impact regulations and implementation of RGGI. The impact of this program review on Dominion's fossil fired generation operations in RGGI states is unknown at this time. Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.

Three of Dominion's facilities, Brayton Point, Salem Harbor and Manchester Street, are subject to RGGI. Beginning with calendar year 2009, RGGI requires that Dominion cover each ton of CO₂ direct stack emissions from these facilities with either an allowance or an offset. The allowances can be purchased through auction or through a secondary market. Dominion has participated in RGGI allowance auctions to date and has procured allowances to meet its estimated compliance requirements under RGGI for 2009, 2010, 2011 and partially for 2012, therefore Dominion does not expect compliance with RGGI to have a material impact on its results of operations or financial condition. However, during August 2011, a lawsuit was filed in New York seeking to retroactively rescind RGGI participation by that state. Currently, a percentage of Dominion's RGGI allowances have been acquired from New York. The acquisition cost of these allowances totaled approximately $34 million, of which the majority have been expensed as consumed. If Dominion is unable to tender New York allowances for RGGI compliance or RGGI does not exchange these allowances for other state allowances, replacement allowances would have to be purchased for 2009 through 2011 compliance. Dominion cannot predict the outcome of the case at this time. Dominion is currently unable to make an estimate of the potential financial statement impacts related to these matters.

In August 2011, the EPA announced a delay in the schedule for proposing regulations which would establish GHG performance standards for new, modified and existing fossil-fired electric generating units. Regulations were expected to be proposed by July 2011 and finalized by May 2012. The schedule for a proposed rulemaking is now delayed beyond October 2011.

Guarantees

Dominion

At September 30, 2011, Dominion had issued $86 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of September 30, 2011, Dominion’s exposure under these guarantees was $54 million, primarily related to certain reserve requirements associated with non-recourse financing.

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

At September 30, 2011, Dominion had issued the following subsidiary guarantees:

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	363	$	363
Commodity transactions(3)	3,182		429
Lease obligation for power generation facility(4)	748		748
Nuclear obligations(5)	231		50
Other(6)	517		141
Total	$	5,041	$	1,731

(1) Represents the estimated portion of the guarantee's stated limit that is utilized as of September 30, 2011 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

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

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

(4) Guarantee of a DEI subsidiary's leasing obligation for Fairless, including a residual value guarantee.

(5) 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.

(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.

Spent Nuclear Fuel

Under provisions of the Nuclear Waste Policy Act of 1982, Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Companies' contracts with the DOE. In January 2004, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims against the DOE requesting damages in connection with its failure to commence accepting spent nuclear fuel. In October 2008, the court issued an opinion and order for Dominion in the amount of approximately $155 million, which includes approximately $112 million in damages incurred by Virginia Power for spent fuel-related costs at Surry and North Anna and approximately $43 million in damages incurred for spent nuclear fuel-related costs at Millstone through June 30, 2006. In December 2008, the government appealed the judgment to the U.S. Court of Appeals for the Federal Circuit. The government's initial brief in the appeal was filed in June 2010. The issues raised by the government on appeal pertained to the damages awarded to Dominion for Millstone. The government did not take issue with the damages awarded to Virginia Power for Surry or North Anna. As a result, Virginia Power recognized a receivable in the amount of $174 million, largely offset against property, plant and equipment and regulatory assets and liabilities, representing certain spent nuclear fuel-related costs incurred through June 30, 2010.

In the second quarter of 2011, the Federal Appeals Court issued a decision affirming the trial court's damages award. The government did not seek rehearing of the Federal Appeals Court decision or seek review by the U.S. Supreme Court. As a result, Dominion recognized a receivable in the amount of $64 million for certain Millstone spent nuclear fuel-related costs incurred through June 30, 2011 that are now considered probable of recovery. Dominion recognized a pre-tax benefit of $24 million, with $17 million recorded in other operations and maintenance expense and $7 million recorded in depreciation, depletion and amortization expense for the six months ended June 30, 2011, with the remainder largely offset against property, plant and equipment. Dominion received payment of the $155 million damages award, including $112 million of damages incurred by Virginia Power, during the third quarter of 2011.

The Companies continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. At September 30, 2011, Dominion's and Virginia Power's receivables for spent nuclear fuel-related costs totaled $99 million and $75 million, respectively. The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Surety Bonds and Letters of Credit

As of September 30, 2011, Dominion had purchased $151 million of surety bonds, including $62 million at Virginia Power, and authorized the issuance of standby letters of credit by financial institutions of $127 million, including $56 million at Virginia Power, to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of the surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

Merchant Generation Operations

Dominion continually reviews its portfolio of assets to determine which assets fit strategically and support its objectives to improve return on invested capital and shareholder value. If Dominion identifies assets that do not support its objectives and believes they may be of greater value to another owner, Dominion may consider such assets for divestiture. In connection with this effort, in the first quarter of 2011, Dominion decided to pursue the sale of Kewaunee. If these efforts are successful, Dominion may be required to present Kewaunee's assets and liabilities that are subject to sale as held for sale in its Consolidated Balance Sheet and Kewaunee's results of operations in discontinued operations in its Consolidated Statements of Income. Held for sale classification would require that amounts be recorded at the lower of book value or sale price less costs to sell and could result in the recording of an impairment charge. Any sale of Kewaunee would be subject to the approval of Dominion's Board of Directors, as well as applicable state and federal approvals.

During the second quarter of 2011, Dominion announced that State Line would shut down by mid-2014, and that it would cease operating two of the four units at Salem Harbor by the end of 2011 and plans to retire all four units on June 1, 2014. In the second quarter of 2011, Dominion recorded a $17 million ($11 million after-tax) charge in other operations and maintenance expense for severance costs related to the expected closings of these merchant generation fac

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Consolidated Statements of Income (USD $) In Millions, except Per Share data	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Operating Revenue	$ 3,803		$ 3,950		$ 11,201		$ 11,451
Operating Expenses
Electric fuel and other energy-related purchases	1,243		1,180		3,270		3,164
Purchased electric capacity	109		116		344		333
Purchased gas	335		367		1,342		1,550
Other operations and maintance	885		788		2,523		2,709
Depreciation, depletion and amortization	268		263		785		794
Other taxes	130		117		416		405
Total operating expenses	2,970		2,831		8,680		8,955
Gain on sale of Appalachian E&P operations	0		0		0		2,467
Income from operations	833		1,119		2,521		4,963
Other income	16		63		112		109
Interest and related charges	249		229		692		600
Income from continuing operations including noncontrolling interests before income tax expense	600		953		1,941		4,472
Income tax expense	204		374		722		1,803
Income from continuing operations including noncontrolling interests	396		579		1,219		2,669
Loss from discontinued operations	0	[1]	0	[1]	0	[1]	(147)	[1]
Net Income Including Noncontrolling Interest	396		579		1,219		2,522
Noncontrolling Interests	4		4		12		12
Net income	392		575		1,207		2,510
Amounts Attributable to Dominion:
Income from continuing operations, net of tax	392		575		1,207		2,657
Income (loss) from discontinued operations, net of tax	0		0		0		(147)
Earnings Per Common Share - Basic
Income from continuing operations	$ 0.69		$ 0.98		$ 2.10		$ 4.49
Loss from discontinued operations	$ 0.00		$ 0.00		$ 0.00		$ (0.25)
Net income attributable to Dominion	$ 0.69		$ 0.98		$ 2.10		$ 4.24
Earnings Per Common Share - Diluted
Income from continuing operations	$ 0.69		$ 0.98		$ 2.10		$ 4.48
Loss from discontinued operations	$ 0.00		$ 0.00		$ 0.00		$ (0.25)
Net income attributable to Dominion	$ 0.69		$ 0.98		$ 2.10		$ 4.23
Dividends paid per common share	$ 0.4925		$ 0.4575		$ 1.4775		$ 1.3725
Discontinued operation tax effect of discontinued operation							13
Virginia Electric and Power Company [Member]
Operating Revenue	2,177		2,111		5,691		5,561
Operating Expenses
Electric fuel and other energy-related purchases	746		694		1,922		1,915
Purchased electric capacity	108		116		342		331
Other	435		319		943		947
Depreciation, depletion and amortization	184		171		533		499
Other taxes	57		53		172		170
Affiliated suppliers	79		85		229		293
Total operating expenses	1,609		1,438		4,141		4,155
Income from operations	568		673		1,550		1,406
Other income	25		25		64		67
Interest and related charges	114		88		290		259
Income from continuing operations including noncontrolling interests before income tax expense	479		610		1,324		1,214
Income tax expense	182		230		508		472
Net income	297		380		816		742
Preferred dividends	4		4		12		12
Balance available for common stock	$ 293		$ 376		$ 804		$ 730

[1] Includes income tax expense of $13 million for the nine months ended September 30, 2010.

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Operating Segments (Tables)

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Segment Reporting Disclosure Other Information

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	X
	LNG import and storage	X
	Producer services	X

Schedule of Segment Reporting Information, by Segment

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

	DVP		Dominion Generation		Dominion Energy		Corporate and Other			Adjustments/Eliminations			Consolidated Total
(millions)
Three Months Ended September 30,
2011
Total revenue from external customers	$	922	$	2,142	$	290	$	23		$	426		$	3,803
Intersegment revenue	21		114		341		149			(625		)	—
Total operating revenue	943		2,256		631		172			(199		)	3,803
Net income (loss) attributable to Dominion	125		394		95		(222		)	—			392
2010
Total revenue from external customers	$	907	$	2,312	$	367	$	(6	)	$	370		$	3,950
Intersegment revenue	16		114		339		172			(641		)	—
Total operating revenue	923		2,426		706		166			(271		)	3,950
Net income (loss) attributable to Dominion	107		487		92		(111		)	—			575
Nine Months Ended September 30,
2011
Total revenue from external customers	$	2,801	$	5,765	$	1,503	$	96		$	1,036		$	11,201
Intersegment revenue	134		271		843		443			(1,691		)	—
Total operating revenue	2,935		6,036		2,346		539			(655		)	11,201
Net income (loss) attributable to Dominion	389		886		368		(436		)	—			1,207
2010
Total revenue from external customers	$	2,697	$	6,121	$	1,667	$	28		$	938		$	11,451
Intersegment revenue	123		324		906		571			(1,924		)	—
Total operating revenue	2,820		6,445		2,573		599			(986		)	11,451
Loss from discontinued operations, net of tax	—		—		—		(147		)	—			(147		)
Net income attributable to Dominion	333		1,088		353		736			—			2,510

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Fair Value Measurements (Net Change in the Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Fair Value Disclosures [Abstract]
Included in earnings	$ (16)	$ 27	$ (24)	$ 40
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	7	4	29	(3)
Fair Value, Measurements, Recurring [Member]
Fair Value Disclosures [Abstract]
Beginning balance	(122)	32	(50)	(66)
Included in earnings	(16)	27	(24)	40
Included in other comprehensive income (loss)	75	(65)	16	20
Included in regulatory assets/liabilities	(3)	(13)	(35)	1
Settlements	24	(23)	47	(41)
Transfers out of Level 3	0	25	4	29
Ending balance	(42)	(17)	(42)	(17)
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	$ 7	$ 4	$ 29	$ (3)

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Derivatives and Hedge Accounting Activities (Schedule of Derivatives not Designated as Hedging Instruments) (Details) (Fair Value - Derivatives not under Hedge Accounting [Member], USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Amount of Gain (Loss) Recognized in Income on Derivatives	$ (7)	[1]	$ 55	[1]	$ 8	[1]	$ 40	[1]
Commodity Contract [Member] | Operating Revenue [Member]
Amount of Gain (Loss) Recognized in Income on Derivatives	15	[1]	45	[1]	56	[1]	71	[1]
Commodity Contract [Member] | Electric Fuel and Other Energy-Related Purchases [Member]
Amount of Gain (Loss) Recognized in Income on Derivatives	(8)	[1]	23	[1]	(16)	[1]	48	[1]
Commodity Contract [Member] | Gas Purchases [Member]
Amount of Gain (Loss) Recognized in Income on Derivatives	(10)	[1]	(13)	[1]	(28)	[1]	(42)	[1]
Interest Rate Contract [Member] | Interest Rate Contract [Member]
Amount of Gain (Loss) Recognized in Income on Derivatives	$ (4)	[1],[2]	$ 0	[1],[2]	$ (4)	[1],[2]	$ (37)	[1],[2]

[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.

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Commitments and Contingencies (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended					1 Months Ended					9 Months Ended		3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Jul. 31, 2011	Dec. 31, 2010		Sep. 30, 2011 Virginia Power [Member]	Sep. 30, 2011 Spent Nuclear Fuel [Member]	Sep. 30, 2011 Spent Nuclear Fuel [Member] Depreciaiton Expense [Member]	Sep. 30, 2011 Spent Nuclear Fuel [Member] Operations and Maintance Expense [Member]	Sep. 30, 2011 Spent Nuclear Fuel [Member] Property Plant and Equipment [Member]	Sep. 30, 2011 Spent Nuclear Fuel [Member] Surry And North Anna [Member]	Sep. 30, 2011 Spent Nuclear Fuel [Member] Millstone Power Station [Member]	Sep. 30, 2011 Employee Severance [Member]	Sep. 30, 2011 Employee Severance [Member]	Sep. 30, 2011 Minimum [Member]	Sep. 30, 2011 Maximum [Member]	Sep. 30, 2011 Third Party and Equity Method Investee [Member]
So2 Emissions Allowances Obtained For Arp And Cair Compliance	$ 57,000,000		$ 57,000,000		$ 57,000,000
Amount of litigation settlement													155,000,000	43,000,000
Receviables For Spent Nuclear Fuel Related Costs									99,000,000
Other receivables	228,000,000		228,000,000			88,000,000	[1]		64,000,000	17,000,000	7,000,000	24,000,000
CAA authorized daily civil penalties for non compliance																	25,000	37,500
Estimated costs to install cooling towers			600,000,000
Amount of expenditures for cooling towers included in planned capital expenditures			100,000,000
Acquisition Cost Of Rggi Allowances	34,000,000
Issued guarantees																			86,000,000
Exposure under guarantees	5,041,000,000		5,041,000,000																54,000,000
Purchased surety bonds	151,000,000		151,000,000
Authorized issuance of standby letters of credit	127,000,000		127,000,000
Other operations and maintance expense relating to severance costs	885,000,000	788,000,000	2,523,000,000	2,709,000,000											17,000,000
Other operations and maintance expense relating to severance costs after tax																11,000,000
Increase In Liability Due To Change In Estimate Of Future Billing Adjustments								$ 35,000,000

[1] Dominion’s Consolidated Balance Sheet at December 31, 2010 has been derived from the audited Consolidated Financial Statements at that date.

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Earnings Per Share (Calculation of Our Basic and Diluted EPS) (Details) (USD $) In Millions, except Per Share data	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Earnings Per Share [Abstract]
Net income (loss) attributable to Dominion	$ 392		$ 575		$ 1,207		$ 2,510
Average shares of common stock outstanding - Basic	569.4		585.0		574.2		591.7
Net effect of potentially dilutive securities	1.8	[1]	1.4	[1]	1.4	[1]	1.1	[1]
Average shares of common stock outstanding - Diluted	571.2		586.4		575.6		592.8
Earnings Per Common Share - Basic	$ 0.69		$ 0.98		$ 2.10		$ 4.24
Earnings Per Common Share - Diluted	$ 0.69		$ 0.98		$ 2.10		$ 4.23

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

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Comprehensive Income (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Stockholders' Equity Note [Abstract]
Net income including noncontrolling interests	$ 396		$ 579		$ 1,219		$ 2,522
Other comprehensive income (loss):
Net other comprehensive loss associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings	(94)	[1]	(56)		(172)	[1]	(61)
Other, net of tax	(76)	[2]	70	[3]	3		86	[3]
Other comprehensive income	(170)		14		(169)		25
Comprehensive income including noncontrolling interests	226		593		1,050		2,547
Noncontrolling Interests	4		4		12		12
Total comprehensive income attributable to Dominion	$ 222		$ 589		$ 1,038		$ 2,535

[1] Primarily reflects unfavorable changes in fair value due to a decrease in interest rates.

[2] Primarily reflects a net decrease in unrealized gains on investments held in nuclear decommissioning trusts.

[3] Primarily reflects a net increase in unrealized gains on investments held in nuclear decommissioning trusts.

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Derivatives and Hedge Accounting Activities (Selected Information Related to Gains (Losses) on Cash Flow Hedges Included in AOCI) (Details) (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
AOCI After-Tax	(121)
Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax	(14)
Commodity Contract [Member]
Maximum Length of Time Hedged in Cash Flow Hedge	44 months
Commodity Contract [Member] | Gas Energy Contract [Member]
AOCI After-Tax	(19)
Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax	(7)
Maximum Length of Time Hedged in Cash Flow Hedge	39 months
Commodity Contract [Member] | Electricity Energy Contract [Member]
AOCI After-Tax	38
Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax	21
Maximum Length of Time Hedged in Cash Flow Hedge	51 months
Commodity Contract [Member] | NGLs Contract [Member]
AOCI After-Tax	(39)
Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax	(24)
Maximum Length of Time Hedged in Cash Flow Hedge	39 months
Commodity Contract [Member] | Other Energy Contract [Member]
AOCI After-Tax	6
Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax	1
Interest Rate Contract [Member]
AOCI After-Tax	(107)
Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax	(5)
Maximum Length of Time Hedged in Cash Flow Hedge	375 months

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Dispositions (Narrative) (Details) (USD $)	1 Months Ended	3 Months Ended	9 Months Ended	1 Months Ended		12 Months Ended
	Feb. 28, 2010	Mar. 31, 2010	Sep. 30, 2010	Apr. 30, 2010 Appalachian E And P [Member] area	Feb. 28, 2010 Peoples [Member]	Dec. 31, 2010 Peoples [Member]
Business Combinations [Abstract]
Proceed from sale				$ 3,500,000,000	$ 542,000,000
Transaction of mineral rights in Marcellus Shale formation (acres)				491,000
After-tax proceeds from agreement to sell Appalachian EP				2,200,000,000
After-tax gain from agreement to sell Appalachian EP			1,400,000,000	1,400,000,000
Write-off of goodwill	79,000,000			134,000,000
Benefit recorded reflecting the reclassification of gains from AOCI to earnings in connection with the discontinuance of hedge accounting for certain cash flow hedges, before tax		42,000,000
Benefit recorded reflecting the reclassification of gains from AOCI to earnings in connection with the discontinuance of hedge accounting for certain cash flow hedges, after tax		25,000,000
Loss on sale of Peoples, after tax					140,000,000
After-tax expenses, including transaction and benefit-related costs, on the sale of Peoples					27,000,000
Income (loss) from discontinued operations, net of tax						$ 12,000,000