10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2012

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	I.R.S. Employer Identification Number
001-08489	DOMINION RESOURCES, INC.	54-1229715
001-02255	VIRGINIA ELECTRIC AND POWER COMPANY	54-0418825
	VIRGINIA (State or other jurisdiction of incorporation or organization)
	120 TREDEGAR STREET RICHMOND, VIRGINIA (Address of principal executive offices)	23219 (Zip Code)
	(804) 819-2000 (Registrants’ telephone number)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
DOMINION RESOURCES, INC.
Common Stock, no par value	New York Stock Exchange
2009 Series A 8.375% Enhanced Junior Subordinated Notes	New York Stock Exchange
VIRGINIA ELECTRIC AND POWER COMPANY
Preferred Stock (cumulative), $100 par value, $5.00 dividend	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark whether the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

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

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Dominion Resources, Inc.    x            Virginia Electric and Power Company    x

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  ¨     Smaller reporting company  ¨

Virginia Electric and Power Company

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

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

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

The aggregate market value of Dominion Resources, Inc. common stock held by non-affiliates of Dominion was approximately $30.0 billion based on the closing price of Dominion’s common stock as reported on the New York Stock Exchange as of the last day of Dominion’s most recently completed second fiscal quarter. Dominion is the sole holder of Virginia Electric and Power Company common stock. As of January 31, 2013, Dominion had 576,309,631 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding.

DOCUMENT INCORPORATED BY REFERENCE.

Portions of Dominion’s 2013 Proxy Statement are incorporated by reference in Part III.

This combined Form 10-K 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 Power makes no representations as to the information relating to Dominion’s other operations.

Dominion Resources, Inc. and

Virginia Electric and Power Company

Item Number		Page Number
	Glossary of Terms	1
Part I
1.	Business	5
1A.	Risk Factors	20
1B.	Unresolved Staff Comments	24
2.	Properties	24
3.	Legal Proceedings	27
4.	Mine Safety Disclosures	27
	Executive Officers of Dominion	28
Part II
5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
6.	Selected Financial Data	30
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
7A.	Quantitative and Qualitative Disclosures About Market Risk	50
8.	Financial Statements and Supplementary Data	52
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	124
9A.	Controls and Procedures (Dominion)	124
9B.	Other Information	127
Part III
10.	Directors, Executive Officers and Corporate Governance	127
11.	Executive Compensation	128
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	151
13.	Certain Relationships and Related Transactions, and Director Independence	151
14.	Principal Accountant Fees and Services	152
Part IV
15.	Exhibits and Financial Statement Schedules	153

Glossary of Terms

The following abbreviations or acronyms used in this Form 10-K 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
2013 Proxy Statement	Dominion 2013 Proxy Statement, File No. 001-08489
ABO	Accumulated benefit obligation
AES	Alternative Energy Solutions
AFUDC	Allowance for funds used during construction
AIP	Annual Incentive Plan
AMI	Advanced Metering Infrastructure
AMR	Automated meter reading program deployed by East Ohio
AOCI	Accumulated other comprehensive income (loss)
AROs	Asset retirement obligations
ARP	Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the CAA
ASA	Average Speed of Answer, a primary metric used to measure customer service
ASLB	Atomic Safety and Licensing Board
ATEX line	Appalachia to Texas Express ethane line
bcf	Billion cubic feet
Bear Garden	A 590 MW combined cycle, natural gas-fired power station in Buckingham County, Virginia
Biennial Review Order	Order issued by the Virginia Commission in November 2011 concluding the 2009 - 2010 biennial review of Virginia Power’s base rates, terms and conditions
Blue Racer	Blue Racer Midstream, LLC
BOEM	Bureau of Ocean Energy Management
BP	BP Wind Energy North America Inc.
Brayton Point	Brayton Point power station
BREDL	Blue Ridge Environmental Defense League
Bremo	Bremo power station
BRP	Dominion Retirement Benefit Restoration Plan
Brunswick County	A proposed 1,358 MW combined cycle, natural gas-fired power station in Brunswick County, Virginia
CAA	Clean Air Act
Caiman	Caiman Energy II, LLC
CAIR	Clean Air Interstate Rule
CAO	Chief Accounting Officer
Carson-to-Suffolk line	Virginia Power 60-mile 500 kV transmission line in southeastern Virginia
CD&A	Compensation Discussion and Analysis
CDO	Collateralized debt obligation
CEO	Chief Executive Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980
CFO	Chief Financial Officer
CFTC	Commodity Futures Trading Commission
CGN Committee	Compensation, Governance and Nominating Committee of Dominion’s Board of Directors
Chesapeake	Chesapeake power station
CNG	Consolidated Natural Gas Company
CNO	Chief Nuclear Officer
CO2	Carbon dioxide
COL	Combined Construction Permit and Operating License
Companies	Dominion and Virginia Power, collectively
CONSOL	CONSOL Energy, Inc.
COO	Chief Operating Officer
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
DCI	Dominion Capital, Inc.
DEI	Dominion Energy, Inc.
Dodd-Frank Act	The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
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

1

Glossary of Terms, continued

Abbreviation or Acronym	Definition
Dominion Direct®	A dividend reinvestment and open enrollment direct stock purchase plan
Dooms-to-Bremo line	Virginia Power project to rebuild approximately 43 miles of existing 115 kV to 230 kV lines, between the Dooms and Bremo substations
Dooms-to-Lexington line	Virginia Power project to rebuild approximately 39 miles of an existing 500 kV line, between the Dooms and Lexington substations
DPP	Dominion’s Defined Benefit Pension Plan
DRS	Dominion Resources Services, Inc.
DSM	Demand-side management
DTI	Dominion Transmission, Inc.
DVP	Dominion Virginia Power operating segment
E&P	Exploration & production
East Ohio	The East Ohio Gas Company, doing business as Dominion East Ohio
EGWP	Employer Group Waiver Plan
Elwood	Elwood power station
Enterprise	Enterprise Product Partners, L.P.
EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005
EPS	Earnings per share
ERISA	The Employment Retirement Income Security Act of 1974
ERM	Enterprise Risk Management
ERO	Electric Reliability Organization
ESRP	Dominion Executive Supplemental Retirement Plan
Excess Tax Benefits	Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation
Fairless	Fairless power station
FASB	Financial Accounting Standards Board
FCM	Futures Commission Merchant
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings Ltd.
Fowler Ridge	A wind-turbine facility joint venture with BP in Benton County, Indiana
Frozen Deferred Compensation Plan	Dominion Resources, Inc. Executives’ Deferred Compensation Plan
Frozen DSOP	Dominion Resources, Inc. Security Option Plan
FTRs	Financial transmission rights
GAAP	U.S. generally accepted accounting principles
GHG	Greenhouse gas
GWSA	Global Warming Solutions Act
Harrisonburg-to-Endless Caverns line	Virginia Power project to construct a 20-mile 230 kV line from the Harrisonburg substation to the Endless Caverns substation
Hayes-to-Yorktown line	Virginia Power project to construct an approximately eight-mile 230 kV transmission line in southeastern Virginia
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
Hope	Hope Gas, Inc., doing business as Dominion Hope
INPO	Institute of Nuclear Power Operations
IRC	Internal Revenue Code
IRS	Internal Revenue Service
ISO	Independent system operator
ISO-NE	ISO New England
Joint Committee	U.S. Congressional Joint Committee on Taxation
June 2006 hybrids	2006 Series A Enhanced Junior Subordinated Notes due 2066
June 2009 hybrids	2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to extensions no later than 2079
Juniper	Juniper Capital L.P.
Kewaunee	Kewaunee nuclear power station
Kincaid	Kincaid power station
kV	Kilovolt
kWh	Kilowatt-hour
LIBOR	London Interbank Offered Rate
LIFO	Last-in-first-out inventory method
LNG	Liquefied natural gas
LTIP	Long-term incentive program
MATS	Utility Mercury and Air Toxics Standard Rule
Manchester Street	Manchester Street power station

2

Abbreviation or Acronym	Definition
mcf	million cubic feet
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Meadow Brook-to-Loudoun line	Virginia Power 65-mile 500 kV transmission line that begins in Warren County, Virginia and terminates in Loudoun County, Virginia
Medicare Act	The Medicare Prescription Drug, Improvement and Modernization Act of 2003
Medicare Part D	Prescription drug benefit introduced in the Medicare Act
MF Global	MF Global Inc.
MGD	Million gallons a day
Millstone	Millstone nuclear power station
MISO	Midwest Independent Transmission System Operators, Inc.
Moody’s	Moody’s Investors Service
Mt. Storm-to-Doubs line	Virginia Power project to rebuild approximately 96 miles of an existing 500 kV transmission line in Virginia and West Virginia
MW	Megawatt
MWh	Megawatt hour
NAAQS	National Ambient Air Quality Standards
NAV	Net asset value
NCEMC	North Carolina Electric Membership Corporation
NedPower	A wind-turbine facility joint venture with Shell in Grant County, West Virginia
NEIL	Nuclear Electric Insurance Limited
NEOs	Named executive officers
NERC	North American Electric Reliability Corporation
NGLs	Natural gas liquids
NO2	Nitrogen dioxide
Non-Employee Directors Plan	Non-Employee Directors Compensation Plan
North Anna	North Anna nuclear power station
North Branch	North Branch power station
North Carolina Commission	North Carolina Utilities Commission
North Carolina Settlement Approval Order	Order issued by the North Carolina Commission in December 2010 approving the Stipulation and Settlement Agreement filed by Virginia Power in connection with the ending of its North Carolina base rate moratorium
NOX	Nitrogen oxide
NPDES	National Pollutant Discharge Elimination System
NRC	Nuclear Regulatory Commission
NSPS	New Source Performance Standards
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
ODEC	Old Dominion Electric Cooperative
Ohio Commission	Public Utilities Commission of Ohio
OSHA	Occupational Safety and Health Administration
PBGC	Pension Benefit Guaranty Corporation
Peoples	The Peoples Natural Gas Company
Pipeline Safety Act	The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011
PIPP	Percentage of Income Payment Plan
PIR	Pipeline Infrastructure Replacement program deployed by East Ohio
PJM	PJM Interconnection, LLC
PM&P	Pearl Meyer & Partners
PNG Companies LLC	An indirect subsidiary of Steel River Infrastructure Fund North America
ppb	Parts-per-billion
Radnor Heights Project	Virginia Power project to construct three new 230 kV underground transmission lines totaling approximately 6 miles and the associated Radnor Heights substation in Arlington County, Virginia
RCCs	Replacement Capital Covenants
RCRA	Resource Conservation and Recovery Act
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
REIT	Real estate investment trust
RGGI	Regional Greenhouse Gas Initiative
Rider A1	A rate adjustment clause to reduce anticipated over-collected fuel expense for the second half of 2012, effective November 1, 2012 to December 31, 2012
Rider B	A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Power’s coal-fired power stations to biomass

3

Abbreviation or Acronym	Definition
Rider BW	A rate adjustment clause associated with the recovery of costs related to Brunswick County
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 T	A rate adjustment clause associated with the recovery of certain electric transmission-related expenditures
Rider T1	A rate adjustment clause to recover the difference between revenues produced from current Rider T rates included in base rates, and the new revenue requirement developed for the rate year beginning September 1, 2012
Rider W	A rate adjustment clause associated with the recovery of costs related to Warren County
Riders C1 and C2	Rate adjustment clauses associated with the recovery of costs related to certain DSM programs
Riders C1A and C2A	Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in the 2011 DSM case
ROE	Return on equity
ROIC	Return on invested capital
RPS	Renewable Portfolio Standard
RTEP	Regional transmission expansion plan
RTO	Regional transmission organization
SAFSTOR	A method of nuclear decommissioning, as defined by the NRC, in which a nuclear facility is placed and maintained in a condition that allows the facility to be safely stored and subsequently decontaminated to levels that permit release for unrestricted use
SAIDI	System Average Interruption Duration Index, metric used to measure electric service reliability
Salem Harbor	Salem Harbor power station
SEC	Securities and Exchange Commission
September 2006 hybrids	2006 Series B Enhanced Junior Subordinated Notes due 2066
Shell	Shell WindEnergy, Inc.
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
Surry-to-Skiffes Creek-to-Whealton lines	Virginia Power project to construct a 7-mile 500 kV line from Surry to the proposed Skiffes Creek Switching Station and a 20-mile 230 kV line from the proposed Skiffes Creek Switching Station to the Whealton substation
TGP	Tennessee Gas Pipeline Company
TSR	Total shareholder return
U.S.	United States of America
U.S. DOT	United States Department of Transportation
UAO	Unilateral Administrative Order
UEX Rider	Uncollectible Expense Rider
VEBA	Voluntary Employees’ Beneficiary Association
VIE	Variable interest entity
Virginia City Hybrid Energy Center	A 600 MW baseload carbon-capture compatible, clean coal powered electric generation facility 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
Warren County	A 1,329 MW combined-cycle, natural gas-fired power station under construction in Warren County, Virginia
Waxpool-Brambleton-BECO line	Virginia Power project to construct an approximately 1.5-mile double circuit 230 kV line to a new Waxpool substation, and a new 230 kV line between the Brambleton and BECO substations
West Virginia Commission	Public Service Commission of West Virginia
Yorktown	Yorktown power station

4

Part I

Item 1. Business

GENERAL

Dominion, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion’s strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. Dominion’s portfolio of assets includes approximately 27,500 MW of generating capacity, 6,300 miles of electric transmission lines, 56,900 miles of electric distribution lines, 11,000 miles of natural gas transmission, gathering and storage pipeline and 21,800 miles of gas distribution pipeline, exclusive of service lines of two inches in diameter or less. Dominion also operates one of the nation’s largest underground natural gas storage systems, with approximately 947 bcf of storage capacity, and serves nearly 6 million utility and retail energy customers in 15 states.

Dominion is focused on expanding its investment in regulated electric generation, transmission and distribution and regulated natural gas transmission and distribution infrastructure within and around its existing footprint. Dominion expects this will continue to increase its earnings contribution from regulated operations, while reducing the sensitivity of its earnings to commodity prices.

Dominion continues to expand and improve its regulated electric and natural gas businesses, in accordance with its five-year capital investment program. A major impetus for this program is to meet the anticipated increase in electricity demand in its electric utility service territory. Other drivers for the capital investment program include the construction of infrastructure to handle the increase in natural gas production from the Marcellus and Utica Shale formations; and to upgrade Dominion’s gas distribution and electric transmission and distribution networks. Planned investments to gather and process natural gas production from the Utica Shale formation, in eastern Ohio and western Pennsylvania, are expected to be made by the newly-formed Blue Racer joint venture.

Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations. Dominion is in the process of transitioning to a more regulated earnings mix as evidenced by its capital investments in regulated infrastructure, as well as dispositions of certain merchant generation facilities during 2012 and its announcement that other merchant generation facilities are expected to be sold or decommissioned in 2013. Dominion’s operations are conducted through various subsidiaries, including Virginia Power.

Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina. In Virginia, Virginia Power conducts business under the name “Dominion Virginia Power” and primarily serves retail customers. In North Carolina, it conducts business under the name “Dominion North Carolina Power” and serves retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, Virginia Power sells electricity at wholesale prices to rural electric cooperatives, municipalities and into wholesale electricity markets. All of Virginia Power’s common stock is owned by Dominion.

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

EMPLOYEES

As of December 31, 2012, Dominion had approximately 15,500 full-time employees, of which approximately 5,800 employees are subject to collective bargaining agreements. As of December 31, 2012, Virginia Power had approximately 6,800 full-time employees, of which approximately 3,100 employees are subject to collective bargaining agreements.

PRINCIPAL EXECUTIVE OFFICES

Dominion and Virginia Power’s principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and their telephone number is (804) 819-2000.

WHERE YOU CAN FIND MORE INFORMATION ABOUT DOMINION AND VIRGINIA POWER

Dominion and Virginia Power file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov. You may also read and copy any document they file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

Dominion and Virginia Power make their SEC filings available, free of charge, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, through Dominion’s internet website, www.dom.com, as soon as practicable after filing or furnishing the material to the SEC. You may also request a copy of these filings, at no cost, by writing or telephoning Dominion at: Corporate Secretary, Dominion, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Information contained on Dominion’s website is not incorporated by reference in this report.

ACQUISITIONS AND DISPOSITIONS

Following are significant divestitures by Dominion and Virginia Power during the last five years. There were no significant acquisitions by either registrant during this period.

SALE OF E&P PROPERTIES

In 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations, including its rights to associated Marcellus acreage, to a subsidiary of CONSOL for approximately $3.5 billion. See Note 3 to the Consolidated Financial Statements for additional information. The historical results of the Appalachian E&P operations are included in the Dominion Energy segment.

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 historical results of these operations are included in the Corporate and Other segment and presented in discontinued operations. See Note 3 to the Consolidated Financial Statements for additional information.

5

ASSIGNMENT OF MARCELLUS ACREAGE

In 2008, Dominion completed a transaction with Antero Resources to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. Dominion received proceeds of approximately $347 million. Under the agreement, Dominion received a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. The overriding royalty interest was transferred to CONSOL as part of the sale of substantially all of Dominion’s Appalachian E&P operations in 2010.

SALE OF CERTAIN DCI OPERATIONS

In March 2008, Dominion reached an agreement to sell its remaining interest in the subordinated notes of a third-party CDO entity held as an investment by DCI and in April 2008 received proceeds of $54 million, including accrued interest. Dominion deconsolidated the CDO entity as of March 31, 2008.

OPERATING SEGMENTS

Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are expected to be or are currently discontinued, which is discussed in Note 3 to the Consolidated Financial Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by Dominion and Virginia Power and their respective legal subsidiaries.

A description of the operations included in the Companies’ primary operating segments is as follows:

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

For additional financial information on operating segments, including revenues from external customers, see Note 25 to the

Consolidated Financial Statements. For additional information on operating revenue related to Dominion’s and Virginia Power’s principal products and services, see Notes 2 and 4 to the Consolidated Financial Statements, which information is incorporated herein by reference.

DVP

The DVP Operating Segment of Virginia Power includes Virginia Power’s regulated electric transmission and distribution (including customer service) operations, which serve approximately 2.5 million residential, commercial, industrial and governmental customers in Virginia and North Carolina.

DVP has announced its five-year investment plan, which includes spending approximately $4.5 billion from 2013 through 2017 to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability. The proposed electric delivery infrastructure projects are intended to address both continued customer growth and increases in electricity consumption by the typical consumer. In addition, data centers continue to contribute to anticipated demand growth, with an expected load of approximately 715 MW by the end of 2013.

Revenue provided by electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Variability in earnings is driven primarily by changes in rates, weather, customer growth and other factors impacting consumption such as the economy and energy conservation, in addition to operating and maintenance expenditures. Operationally, electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. As a result, electric service reliability and customer service have improved. The three-year average SAIDI has improved from 125 minutes at the end of 2007 to 105 minutes at the end of 2012. Likewise, ASA has also shown significant improvement. The three-year average ASA has improved from 57 seconds at the end of 2007 to 38 seconds at the end of 2012. Customer service options continue to be enhanced and expanded through the use of technology. Customers now have the ability to use the Internet for routine billing and payment transactions, connecting and disconnecting service, reporting outages and obtaining outage updates. Additionally, customers can follow progress of electric service restoration efforts following major outages by accessing Facebook or Twitter. In the future, safety, electric service reliability and customer service will remain key focal areas for electric distribution.

Revenue provided by Virginia Power’s electric transmission operations is based primarily on rates approved by FERC. The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings primarily results from changes in rates and the timing of property additions, retirements and depreciation.

Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to NERC by EPACT, Virginia Power’s electric transmission operations are committed to meeting NERC standards, modernizing its infrastructure and maintaining superior system reliability. Virginia Power’s electric transmission operations will continue to focus on

6

safety, operational performance, NERC compliance and execution of PJM’s RTEP.

The DVP Operating Segment of Dominion includes all of Virginia Power’s regulated electric transmission and distribution operations as discussed above, as well as Dominion’s nonregulated retail energy marketing operations.

Dominion’s retail energy marketing operations compete in nonregulated energy markets. The retail business requires limited capital investment and currently employs approximately 190 people. The retail customer base includes 2.1 million customer accounts and is diversified across three product lines-natural gas, electricity and energy-related products and services. Dominion has a heavy concentration of natural gas customers in markets where utilities have a long-standing commitment to customer choice. Dominion pursues customers in electricity markets where utilities have divested of generation assets and where customers are permitted and have opted to purchase from the market. Major growth drivers are net customer additions, new market penetration, product development and expanded sales channels and supply optimization.

COMPETITION

DVP Operating Segment—Dominion and Virginia Power

Within Virginia Power’s service territory in Virginia and North Carolina, there is no competition for electric distribution service. Additionally, since its electric transmission facilities are integrated into PJM, electric transmission services are administered by PJM and are not subject to competition in relation to transmission service provided to customers within the PJM region. Virginia Power is seeing continued growth in new customers in its transmission and distribution operations. In its Order 1000 compliance filing, PJM has proposed tariff changes that, if approved by FERC, could allow certain transmission facilities to be constructed in Virginia Power’s service territory by entities other than Virginia Power beginning in 2013.

DVP Operating Segment—Dominion

Dominion’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas and electricity. Customers in these markets have the right to select a retail marketer and typically do so based upon price savings or price stability; however, incumbent utilities have the advantage of long-standing relationships with their customers and greater name recognition in their markets.

REGULATION

Virginia Power’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia Commission and the North Carolina Commission. Virginia Power’s wholesale electric transmission rates, tariffs and terms of service are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. See State Regulations and Federal Regulations in Regulation and Note 13 to the Consolidated Financial Statements for additional information, including a discussion of the 2011 Biennial Review Order.

PROPERTIES

Virginia Power has approximately 6,300 miles of electric transmission lines of 69 kV or more located in the states of North Carolina, Virginia and West Virginia. Portions of Virginia Power’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.

Each year, as part of PJM’s RTEP process, reliability projects are authorized. In December 2012, Virginia Power completed construction of the Hayes-to-Yorktown line at a total project cost of $79 million. This previously authorized PJM project was designed to improve the reliability of service to customers and the region. Previously approved PJM-authorized reliability projects such as the Waxpool-Brambleton-BECO line ($49 million), the Harrisonburg-to-Endless Caverns line ($66 million) the Radnor Heights Project ($81 million), and the Dooms-to-Bremo line ($65 million) continue to progress and are expected to be completed on time.

As part of subsequent annual PJM RTEP processes, PJM authorized additional electric transmission upgrade projects including the Mt. Storm-to-Doubs line ($350 million) in December 2010 and the Surry-to-Skiffes Creek-to-Whealton lines ($155 million) in 2012. Also approved as a reliability project in 2012 was the Dooms-to-Lexington line ($112 million). See Note 13 to the Consolidated Financial Statements for additional information regarding electric transmission projects.

In addition, Virginia Power’s electric distribution network includes approximately 56,900 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owners of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.

SOURCES OF ENERGY SUPPLY

DVP Operating Segment—Dominion and Virginia Power

DVP’s supply of electricity to serve Virginia Power customers is produced or procured by Dominion Generation. See Dominion Generation for additional information.

DVP Operating Segment—Dominion

The supply of electricity to serve Dominion’s retail energy marketing customers is procured through market wholesalers and RTO or ISO transactions. The supply of gas to serve Dominion’s retail energy marketing customers is procured through market wholesalers or by Dominion Energy. See Dominion Energy for additional information.

SEASONALITY

DVP Operating Segment—Dominion and Virginia Power

DVP’s earnings vary seasonally as a result of the impact of changes in temperature, the impact of storms and other cata-

7

strophic weather events, and the availability of alternative sources for heating on demand by residential and commercial customers.

Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree days for DVP’s electric-utility related operations does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials and because alternative heating sources are more readily available.

DVP Operating Segment—Dominion

The earnings of Dominion’s retail energy marketing operations also vary seasonally. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, while the demand for gas peaks during the winter months to meet heating needs.

Dominion Generation

The Dominion Generation Operating Segment of Virginia Power includes the generation operations of the Virginia Power regulated electric utility and its related energy supply operations. Virginia Power’s utility generation operations primarily serve the supply requirements for the DVP segment’s utility customers.

Earnings for the Generation operating segment of Virginia Power primarily result from the sale of electricity generated by its utility fleet. Revenue is based primarily on rates established by state regulatory authorities and state law. Approximately 80% of revenue comes from serving Virginia jurisdictional customers. Rates for the Virginia jurisdiction are set using a modified cost-of-service rate model. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. Variability in earnings for Virginia Power’s generation operations results from changes in rates, the demand for services, which is primarily weather dependent, and labor and benefit costs, as well as the timing, duration and costs of scheduled and unscheduled outages. See Electric Regulation in Virginia under Regulation and Note 13 to the Consolidated Financial Statements for additional information.

The Dominion Generation Operating Segment of Dominion includes Virginia Power’s generation facilities and its related energy supply operations described above as well as the generation operations of Dominion’s merchant fleet and energy marketing and price risk management activities for these assets. The Generation operating segment of Dominion derives its earnings primarily from the sale of electricity generated by Virginia Power’s utility and Dominion’s merchant generation assets, as well as from associated capacity and ancillary services.

Variability in earnings provided by Dominion’s merchant fleet relates to changes in market-based prices received for electricity and capacity. Market-based prices for electricity are largely dependent on commodity prices, primarily natural gas, and the demand for electricity, which is primarily dependent upon weather. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion manages electric and capacity price volatility of its merchant fleet by hedging a substantial portion of its expected near-term sales with

derivative instruments and also entering into long-term power sales agreements. However, earnings have been adversely impacted due to a sustained decline in commodity prices. This sustained decline in power prices in conjunction with Dominion’s regular strategic review of its portfolio of assets has led to its decision to pursue the sale or retirement of certain merchant generation assets, which is discussed in more detail below. Variability also results from changes in the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages.

COMPETITION

Dominion Generation Operating Segment—Dominion and Virginia Power

Virginia Power’s generation operations are not subject to significant competition as only a limited number of its Virginia jurisdictional electric utility customers have retail choice. See Regulation-State Regulations-Electric for more information. Currently, North Carolina does not offer retail choice to electric customers.

Dominion Generation Operating Segment—Dominion

Unlike Dominion Generation’s regulated generation fleet, its merchant generation fleet is dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that allows for a rate of return on its capital investments. Competition for the merchant fleet is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact the merchant fleet’s ability to profit from the sale of electricity and related products and services.

Dominion Generation’s merchant generation fleet owns and operates several facilities in the Midwest that operate within functioning RTOs. A significant portion of the output from these facilities is sold under long-term contracts, the majority of which expire between December 31, 2012 and December 31, 2013, and is therefore largely unaffected by price competition during the terms of these contracts. It was announced during the third quarter of 2012 that Dominion would pursue the sale of these Midwest assets, excluding its wind facilities. In the fourth quarter of 2012, Dominion announced that Kewaunee is expected to be decommissioned beginning in 2013.

Dominion Generation’s other merchant assets also operate within functioning RTOs and primarily compete on the basis of price. Competitors include other generating assets bidding to operate within the RTOs. These RTOs have clearly identified market rules that ensure the competitive wholesale market is functioning properly. Dominion Generation’s merchant units compete in the spot market with other generators to sell a variety of products including energy, capacity and ancillary services. It is difficult to compare various types of generation given the wide range of fuels, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, Dominion applies its expertise in operations, dispatch and risk management to maximize the degree to which its merchant fleet is competitive compared to similar assets within the region.

8

REGULATION

Virginia Power’s utility generation fleet and Dominion’s merchant generation fleet are subject to regulation by FERC, the NRC, the EPA, the DOE, the Army Corps of Engineers and other federal, state and local authorities. Virginia Power’s utility generation fleet is also subject to regulation by the Virginia Commission and the North Carolina Commission. See State Regulations and Federal Regulations in Regulation for more information.

PROPERTIES

For a listing of Dominion’s and Virginia Power’s existing generation facilities, see Item 2. Properties.

Dominion Generation Operating Segment—Dominion and Virginia Power

The generation capacity of Virginia Power’s electric utility fleet totals 17,708 MW. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro and renewables. Virginia Power’s generation facilities are located in Virginia, West Virginia and North Carolina and serve load in Virginia and northeastern North Carolina.

Based on available generation capacity and current estimates of growth in customer demand in its utility service area, Virginia Power will need additional generation capacity over the next decade. Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the anticipated growing demand in its core market in Virginia. Significant projects under construction or development are set forth below:

Ÿ In February 2012, the Virginia Commission authorized the construction of Warren County which is estimated to cost approximately $1.1 billion, excluding financing costs. It is expected to generate approximately 1,329 MW of electricity when operational. Commercial operations are scheduled to commence by late 2014. In connection with the air permit process for Warren County, Virginia Power reached an agreement to permanently retire North Branch, a 74 MW coal-fired plant located in West Virginia, once Warren County begins commercial operations. During the fourth quarter of 2012, Virginia Power sold North Branch to a salvage company that plans to demolish the station and resell the land.

Ÿ Virginia Power is converting three coal-fired Virginia generating stations to biomass, a renewable energy source. The conversions of the power stations in Altavista, Hopewell and Southampton County will increase Dominion’s renewable generation by more than 150 MW and are expected to cost approximately $157 million, excluding financing costs. Construction activities have started at all three sites, and these conversions are expected to be complete by the end of 2013.

Ÿ Subject to the receipt of certain regulatory approvals, Virginia Power plans to construct Brunswick County, which is expected to generate approximately 1,358 MW when operational. If the project is approved, commercial operations are expected to commence in 2016, at an estimated cost of approximately $1.3 billion, excluding financing costs. A

conditional use permit has been approved to allow for construction of the plant. Brunswick County would offset the expected reduction in capacity caused by the planned retirement of coal-fired units at Chesapeake and Yorktown by 2015 primarily due to the cost of compliance with MATS.

Ÿ Subject to the necessary regulatory approvals, Virginia Power plans to convert Bremo Units 3 and 4 from coal to natural gas. This project would preserve the 227 MW of capacity from the units and is expected to cost approximately $53 million, excluding financing costs. The conversion process is expected to be complete in 2014 in compliance with the Virginia City Hybrid Energy Center air permit.

The Virginia City Hybrid Energy Center located in Wise County, Virginia started commercial operations in July 2012. The summer capacity of this clean coal generating facility is approximately 600 MW. The project cost was approximately $1.8 billion, excluding financing and supplemental costs.

In addition to the projects above, Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. See Note 13 to the Consolidated Financial Statements for more information on this project.

Dominion Generation Operating Segment—Dominion

The generation capacity of Dominion’s merchant fleet totals 7,880 MW, including 3,954 MW of announced planned facility divestitures and decommissionings. The remaining generation mix is diversified and includes nuclear, gas, and renewables. Merchant generation facilities are located in Connecticut, Indiana, Pennsylvania, Rhode Island and West Virginia with a majority of that capacity concentrated in New England.

Dominion continually reviews its portfolio of assets to determine which assets fit strategically and support its objectives to improve ROIC and shareholder value. In connection with these efforts, previously Dominion had announced its intention to retire State Line and Salem Harbor. During the second quarter of 2012, Dominion sold State Line, which ceased operations in March 2012, and in August 2012, Dominion completed the sale of Salem Harbor. In the third quarter of 2012, Dominion announced its intention to pursue the sale of its coal-fired merchant power stations, Brayton Point and Kincaid, and its 50% equity method investment in Elwood. In April 2011, Dominion announced the decision to pursue the sale of Kewaunee. In the fourth quarter of 2012, Dominion announced plans to close and decommission Kewaunee after the company was unable to find a buyer for the nuclear facility. Kewaunee is expected to cease power production in the second quarter of 2013 and commence decommissioning activities.

SOURCES OF ENERGY SUPPLY

Dominion Generation Operating Segment—Dominion and Virginia Power

Dominion Generation uses a variety of fuels to power its electric generation and purchases power for utility system load requirements and to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are included as contractual obligations in Future Cash Payments for Contractual Obligations and Planned Capital Expenditures in Item 7. MD&A.

9

Nuclear Fuel—Dominion Generation primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.

Fossil Fuel—Dominion Generation primarily utilizes coal and natural gas in its fossil fuel plants.

Dominion Generation’s coal supply is obtained through long-term contracts and short-term spot agreements from both domestic and international suppliers.

Dominion Generation’s natural gas and oil supply is obtained from various sources including: purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, purchases from local producers in the Appalachian area, purchases from gas marketers and withdrawals from underground storage fields owned by Dominion or third parties.

Dominion Generation manages a portfolio of natural gas transportation contracts (capacity) that allows flexibility in delivering natural gas to its gas turbine fleet, while minimizing costs.

Purchased Power—Dominion Generation purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for utility system load requirements.

Dominion Generation also occasionally purchases electricity from the PJM, ISO-NE and MISO spot markets to satisfy physical forward sale requirements as part of its merchant generation operations.

Dominion Generation Operating Segment—Virginia Power

Presented below is a summary of Virginia Power’s actual system output by energy source:

Source	2012			2011			2010
Nuclear(1)		33	%		28	%		28	%
Purchased power, net		27			33			29
Coal(2)		22			26			31
Natural gas		17			12			10
Other(3)		1			1			2
Total		100	%		100	%		100	%

(1) Excludes ODEC’s 11.6% ownership interest in North Anna.

(2) Excludes ODEC’s 50.0% ownership interest in the Clover power station. The average cost of coal for 2012 Virginia in-system generation was $33.00 per MWh.

(3) Includes oil, hydro and biomass.

SEASONALITY

Sales of electricity for Dominion Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree days does not produce the same increase in revenue as an increase in cooling degree days, due to seasonal pricing differentials at Virginia Power and because alternative heating sources are more readily available.

NUCLEAR DECOMMISSIONING

In June 2011, the NRC amended its regulations to improve decommissioning planning. As applied to the operators of nuclear power plants, these amendments require licensees to conduct operations in a manner minimizing introduction of residual radioactivity into the site, perform additional surveys, and maintain records of their results. In addition, the amendments make minor changes to financial assurance methods and require additional information on decommissioning and spent fuel management costs after a plant permanently ceases operations. The revised regulations became effective in December 2012 and did not significantly affect the decommissioning cost estimates or funding for Dominion’s or Virginia Power’s units.

Dominion Generation Operating Segment—Dominion and Virginia Power

Virginia Power has a total of four licensed, operating nuclear reactors at Surry and North Anna in Virginia.

Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers and placed into trusts have been invested to fund the expected future costs of decommissioning the Surry and North Anna units.

Virginia Power believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects the long-term investment horizon, since the units will not be decommissioned for decades, and a positive long-term outlook for trust fund investment returns. Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC.

The estimated cost to decommission Virginia Power’s four nuclear units is reflected in the table below and is primarily based upon site-specific studies completed in 2009. These cost studies are generally completed every four years. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Virginia Power expects to decommission the Surry and North Anna units during the period 2032 to 2067.

Dominion Generation Operating Segment—Dominion

In addition to the four nuclear units discussed above, Dominion has three licensed, operating nuclear reactors, two at Millstone in Connecticut and one at Kewaunee in Wisconsin. A third Millstone unit ceased operations before Dominion acquired the power station. In October 2012, Dominion announced that it plans to cease operations at Kewaunee in 2013 and commence decommissioning activities using the SAFSTOR methodology. The planned decommissioning completion date is 2073, which is within the NRC allowed 60 year window.

As part of Dominion’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Any funds remaining in Kewaunee’s trust after decom-

10

missioning is completed are required to be refunded to Wisconsin ratepayers. Dominion believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Dominion will continue to monitor these trusts to ensure they meet the NRC financial assurance requirements, which may include, if needed, the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC. The estimated cost to decommission Dominion’s eight units is reflected in the table below and is primarily based upon site-specific studies completed in 2009, with the exception of Kewaunee for which a site-specific study was initiated in 2012 and subsequently finalized in early 2013. For the Millstone operating units, the current cost estimate assumes decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Millstone Unit 1 is in SAFSTOR decommissioning status and will continue to be monitored until full decommissioning activities begin for the remaining Millstone operating units. Dominion expects to start minor decommissioning activities at Millstone Unit 2 in 2035, with full decommissioning of Millstone Units 1, 2 and 3 following the permanent cessation of operations of Millstone Unit 3 during the period 2045 to 2069.

The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion and Virginia Power are shown in the following table:

	NRC license expiration year		Most recent cost estimate (2012 dollars)(1)		Funds in trusts at December 31, 2012		2012 contributions to trusts
(dollars in millions)
Surry
Unit 1		2032	$	496	$	429	$	0.6
Unit 2		2033		520		422		0.6
North Anna
Unit 1(2)		2038		432		342		0.4
Unit 2(2)		2040		443		322		0.3
Total (Virginia Power)				1,891		1,515		1.9
Millstone
Unit 1(3)		n/a		455		356		—
Unit 2		2035		568		444		—
Unit 3(4)		2045		671		437		—
Kewaunee								—
Unit 1		2033		666		578		—
Total (Dominion)			$	4,251	$	3,330	$	1.9

(1) The cost estimates shown above reflect reductions for the expected future recovery of certain spent fuel costs based on the Companies’ contracts with the DOE for disposal of spent nuclear fuel consistent with the reductions reflected in Dominion’s and Virginia Power’s nuclear decommissioning AROs.

(2) North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect 89.26% of the decommissioning cost for both of North Anna’s units.

(3) Unit 1 permanently ceased operations in 1998, before Dominion’s acquisition of Millstone.

(4) Millstone Unit 3 is jointly owned by Dominion Nuclear Connecticut, with a 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and Green Mountain Power Corporation. Decommissioning cost is shown at Dominion’s ownership percentage. At December 31, 2012, the minority owners held approximately $28 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.

Also see Note 14 and Note 22 to the Consolidated Financial Statements for further information about AROs and nuclear decommissioning, respectively.

Dominion Energy

Dominion Energy includes Dominion’s regulated natural gas distribution companies, regulated gas transmission pipeline and storage operations, natural gas gathering and by-products extraction activities, regulated LNG operations and its investment in the Blue Racer joint venture. Dominion Energy also includes producer services, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates.

The gas transmission pipeline and storage business serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in Dominion’s gas transmission pipeline and storage business is its gas gathering and extraction activity, which sells extracted products at market rates. Dominion’s LNG operations involve the import and storage of LNG at Cove Point and the transportation of regasified LNG to the interstate pipeline grid and mid-Atlantic and Northeast markets. In connection with the recent increase in Eastern U.S. natural gas production, including from the Marcellus and Utica Shale formations, Dominion has requested regulatory authority to operate Cove Point as a bi-directional facility, able to import LNG, and vaporize it as natural gas, and liquefy natural gas and export it as LNG. See Future Issues and Other Matters in MD&A for more information. The Blue Racer joint venture will concentrate on building new gathering, processing, fractionation and NGL transportation assets as the development of the Utica Shale formation increases. Dominion will contribute to the joint venture a network of wet gas gathering assets, the Natrium extraction plant and other assets.

Revenue provided by Dominion’s regulated gas transmission and storage and LNG operations is based primarily on rates established by FERC. Additionally, Dominion receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain gas transportation, gas storage, LNG storage and regasification services. Dominion’s gas distribution operations serve residential, commercial and industrial gas sales, transportation and gathering service customers. Revenue provided by its gas distribution operations is based primarily on rates established by the Ohio and West Virginia Commissions. The profitability of these businesses is dependent on Dominion’s ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.

In October 2008, East Ohio implemented a rate case settlement which provided for a straight-fixed-variable rate design for a majority of its customers. Under this rate design, East Ohio recovers a larger portion of its fixed operating costs through a flat monthly charge accompanied by a reduced volumetric base delivery rate. Accordingly, East Ohio’s revenue is less impacted by weather-related fluctuations in natural gas consumption than under the traditional rate design.

11

Earnings from Dominion Energy’s producer services business are unregulated, and are subject to variability associated with changes in commodity prices. Producer services uses physical and financial arrangements to hedge this price risk.

COMPETITION

Dominion Energy’s gas transmission operations compete with domestic and Canadian pipeline companies. Dominion also competes with gas marketers seeking to provide or arrange transportation, storage and other services. Alternative energy sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain long-line pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enable Dominion to tailor its services to meet the needs of individual customers.

Retail competition for gas supply exists to varying degrees in the two states in which Dominion’s gas distribution subsidiaries operate. In Ohio, there has been no legislation enacted to require supplier choice for residential natural gas consumers. However, Dominion has offered an Energy Choice program to residential and commercial customers since October 2000. In January 2013, the Ohio Commission granted East Ohio’s motion to fully exit the merchant function for its nonresidential customers, beginning in April 2013, which will require those customers to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2012, approximately 1 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice Program. West Virginia does not require customers to choose their provider in its retail natural gas markets at this time. See Regulation-State Regulations-Gas for additional information.

REGULATION

Dominion Energy’s natural gas transmission pipeline, storage and LNG operations are regulated primarily by FERC. Dominion Energy’s gas distribution service, including the rates that it may charge customers, is regulated by the Ohio and West Virginia Commissions. See State Regulations and Federal Regulations in Regulation for more information.

PROPERTIES

Dominion Energy’s gas distribution network is located in the states of Ohio and West Virginia. This network involves approximately 21,800 miles of pipe, exclusive of service lines of two inches in diameter or less. The rights-of-way grants for many natural gas pipelines have been obtained from the actual owners of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.

Dominion Energy has approximately 11,000 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy operates gas processing and fractionation facilities in West Virginia with a total processing capacity of

267,000 mcf per day and fractionation capacity of 582,000 gallons per day. Dominion Energy also operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with almost 2,000 storage wells and approximately 349,000 acres of operated leaseholds.

The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 947 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy. The capacity of those fields owned by Dominion’s partners totals about 242 bcf. Dominion Energy also has about 15 bcf of above-ground storage capacity at Cove Point. Dominion Energy has 133 compressor stations with more than 832,000 installed compressor horsepower.

In 2012, DTI completed the Gathering Enhancement Project, a $200 million expansion of its natural gas gathering, processing and liquids facilities in West Virginia. The project is designed to increase the efficiency and reduce high pressures in its gathering system, thus increasing the amount of natural gas local producers can move through DTI’s West Virginia system.

In September 2012, DTI completed the $575 million Appalachian Gateway Project. The project provides approximately 484,000 dekatherms per day of firm transportation services for new Appalachian gas supplies in West Virginia and southwestern Pennsylvania to an interconnection with Texas Eastern Transmission, LP at Oakford, Pennsylvania.

In November 2012, DTI completed the $97 million Northeast Expansion Project. The project provides 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.

In November 2012, DTI completed the $46 million Ellisburg-to-Craigs project. The project’s capacity of approximately 150,000 dekatherms per day is 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.

In November 2011, DTI filed a FERC application for approval to construct the $17 million Sabinsville-to-Morrisville project, a pipeline to move additional Marcellus supplies from a TGP pipeline in northeast Pennsylvania to its line in upstate New York. DTI executed a binding precedent agreement with TGP in October 2010 to provide this firm transportation service up to 92,000 dekatherms per day for a 14-year term. Construction is expected to commence in April 2013 with an expected in service date of November 2013.

In December 2012, DTI received FERC authorization for the Allegheny Storage Project, which is expected to provide approximately 7.5 bcf of incremental storage service and 125,000 dekatherms per day of associated year-round firm transportation service to three local distribution companies under 15-year contracts. Storage capacity for the project will be provided from storage pool enhancements at DTI and capacity leased from East Ohio. DTI intends to construct additional compression facilities and upgrade measurement and regulation in order to provide 115,000 dekatherms per day of transportation service. The remaining 10,000 dekatherms per day of transportation service will not require construction of additional facilities. The $112 million project is expected to be in service in 2014.

12

In February 2011, DTI concluded a binding open season for its $67 million Tioga Area Expansion Project, which is designed to provide approximately 270,000 dekatherms per day of firm transportation service from supply interconnects in Tioga and Potter Counties in Pennsylvania to DTI’s Crayne interconnect with Texas Eastern Transmission, LP in Greene County, Pennsylvania and the Leidy interconnect with Transcontinental Gas Pipe Line Company in Clinton County, Pennsylvania. Two customers have contracted for the service under 15-year terms. DTI filed a certificate application with FERC in November 2011. Subject to the receipt of regulatory approvals, the project is anticipated to be in service in November 2013.

In January 2011, Dominion announced the development of a natural gas processing and fractionation facility in Natrium, West Virginia, and in July 2011 it executed a contract for the construction of the first phase of the facility. This first phase of the project is fully contracted and is expected to be in service by March 2013. Once completed, the plant and related facilities are expected to be contributed into the Blue Racer joint venture. The Phase 1 costs for processing, fractionation, plant inlet and outlet natural gas transportation, gathering, and various modes of NGL transportation are approximately $550 million.

In May 2012, Dominion began construction of a $125 million pipeline project, which is included in the Natrium cost estimate above. The pipeline is designed to transport approximately 27,000 barrels per day of ethane from the Natrium facility to an interconnect with the ATEX line of Enterprise near Follansbee, West Virginia. Dominion NGL Pipelines, LLC, a subsidiary of Dominion, owns the 58-mile pipeline and associated equipment. Following the installation of the pipeline and the satisfaction of certain other conditions, Dominion NGL Pipelines, LLC is also expected to be contributed to Blue Racer. The facilities are anticipated to be available the later of January 1, 2014 or the date Enterprise commences operation of the ATEX line. Transportation services on the pipeline will be subject to FERC regulation under the Interstate Commerce Act.

In November 2012, DTI filed a FERC application for approval to construct the $42 million Natrium to Market project. The project is designed to provide 185,000 dekatherms per day of firm transportation from an interconnect between DTI and the Natrium facility to DTI’s interconnect with Texas Eastern Transmission, LP in Greene County Pennsylvania. Four customers have entered into binding precedent agreements for the full project capacity under 8-year and 13-year terms. Subject to the receipt of regulatory approvals, the project is anticipated to be in service in November 2014.

In 2008, East Ohio began PIR, aimed at replacing approximately 20% of its pipeline system. The $2.7 billion, 25-year program is ongoing. See Note 13 to the Consolidated Financial Statements for further information about PIR.

SOURCES OF ENERGY SUPPLY

Dominion Energy’s natural gas supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area and gas marketers. Dominion’s large underground natural gas storage network and the location of its pipeline system are a significant link between the country’s major interstate gas pipelines and large markets in the Northeast

and mid-Atlantic regions. Dominion’s pipelines are part of an interconnected gas transmission system, which provides access to supplies nationwide for local distribution companies, marketers, power generators and industrial and commercial customers.

Dominion’s underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Northeast, mid-Atlantic and Midwest regions. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transmission capacity.

SEASONALITY

Dominion Energy’s natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March; however implementation of the straight-fixed-variable rate design at East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipeline and storage business can also be weather sensitive. Commodity prices can be impacted by seasonal weather changes, the effects of unusual weather events on operations and the economy. Dominion’s producer services business is affected by seasonal changes in the prices of commodities that it transports, stores and actively markets and trades.

Corporate and Other

Corporate and Other Segment—Virginia Power

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

Corporate and Other Segment—Dominion

Dominion’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are expected to be and are currently discontinued, which is discussed in Note 3 to the Consolidated Financial Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

ENVIRONMENTAL STRATEGY

Dominion and Virginia Power are committed to being good environmental stewards. Their ongoing objective is to provide reliable, affordable energy for their customers while being environmentally responsible. The integrated strategy to meet this objective consists of five major elements:

Ÿ Compliance with applicable environmental laws, regulations and rules;

Ÿ Conservation and load management;

Ÿ Renewable generation development;

Ÿ Other generation development to maintain fuel diversity, including clean coal, advanced nuclear energy, and natural gas; and

Ÿ Improvements in other energy infrastructure.

13

This strategy incorporates Dominion’s and Virginia Power’s efforts to voluntarily reduce GHG emissions, which are described below. See Dominion Generation—Properties for more information on certain of the projects described below, as well as other projects under current development. In addition to the environmental strategy described above, Dominion formed the AES department in April 2009 to conduct research in the renewable and alternative energy technologies sector and to support strategic investments to advance Dominion’s degree of understanding of such technologies.

Environmental Compliance

Dominion and Virginia Power remain committed to compliance with all applicable environmental laws, regulations and rules related to their operations. Additional information related to Dominion’s and Virginia Power’s environmental compliance matters can be found in Future Issues and Other Matters in Item 7. MD&A and in Note 22 to the Consolidated Financial Statements.

Conservation and Load Management

Conservation plays a significant role in meeting the growing demand for electricity. The Regulation Act provides incentives for energy conservation and sets a voluntary goal for Virginia to reduce electricity consumption by retail customers in 2022 by ten percent of the amount consumed in 2006 through the implementation of conservation programs. Legislation in 2009 added definitions of peak-shaving and energy efficiency programs, and allowed for a margin on operating expenses and revenue reductions related to energy efficiency programs.

Virginia Power’s DSM programs provide important incremental steps toward achieving the voluntary ten percent energy conservation goal. The conservation and load management plan includes the following DSM programs, which were approved by the Virginia Commission in March 2010 and rolled out in May 2010:

Ÿ Residential Lighting Program—an instant, in-store discount on the purchase of qualifying compact fluorescent lights; this program ended in Virginia on December 31, 2011;

Ÿ Residential Low Income Program—free energy audit for income-qualifying customers, which identifies, installs improvements and suggests additional implementation measures that will help these customers save money on energy bills;

Ÿ Residential Air Conditioner Cycling Program—incentives for residential customers who allow Virginia Power to cycle their central air conditioners and heat pump systems during peak periods;

Ÿ Commercial Heating, Ventilating and Air Conditioning Upgrade Program—incentives for commercial customers to improve the energy efficiency of their heating and/or cooling units; and

Ÿ Commercial Lighting Program—incentives for commercial customers to install energy-efficient lighting.

In September 2011, Virginia Power filed an application for approval of several DSM programs and for additional funding for the approved Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs, in addition to requesting annual recovery of DSM program costs. In April 2012, the Virginia Commission approved the following programs:

Ÿ Commercial Energy Audit Program—an on-site energy audit providing commercial customers information to evaluate potential energy cost savings options;

Ÿ Commercial Duct Testing & Sealing—an incentive for commercial customers to seal duct and air distribution systems to improve system efficiency;

Ÿ Commercial Distributed Generation—a program for customers to operate their on-site back-up generators when requested by Virginia Power during periods of peak demand; and

Ÿ Residential Bundle Program—a bundle of four residential programs to be available to qualifying residential customers, including the Residential Home Energy Check-up Program, Residential Duct Testing & Sealing Program, Residential Heat Pump Tune-Up Program and Residential Heat Pump Upgrade Program.

The Virginia Commission denied additional funding for the Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs. As a result, Virginia Power began winding down these programs in the second quarter of 2012. These two programs are no longer available in Virginia.

In August 2012, Virginia Power filed an application for approval to extend two residential DSM programs (the Air Conditioner Cycling program and the Low Income program) beyond April 30, 2013 for periods of five years and two years, respectively. Virginia Power also filed for approval of updated rate adjustment clauses for DSM program cost recovery, and for Electric Vehicle Pilot Program cost recovery. This case is pending.

In September 2010, Virginia Power filed with the North Carolina Commission an application for approval and its initial request for cost recovery of the five DSM programs initially approved in Virginia in 2010, as well as the distributed generation program. In February 2011, the North Carolina Commission approved the five DSM programs approved in Virginia, and Virginia Power subsequently launched the residential lighting program in May 2011 and the remainder of the approved Virginia DSM programs in June 2011. The Residential Lighting Program ended in North Carolina on December 31, 2011. In a separate order issued in September of 2011, the North Carolina Commission denied approval of Virginia Power’s proposed distributed generation program.

In August 2011, Virginia Power filed with the North Carolina Commission an application for approval and its updated request for cost recovery of the five DSM programs approved in North Carolina, as well as the then-pending distributed generation program. In December 2011, the North Carolina Commission approved updated cost recovery for the five DSM programs, as Virginia Power withdrew its cost recovery request for the distributed generation program. In a separate order issued in August 2012, the North Carolina Commission approved Virginia Power’s request to suspend the Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs which had been wound down and closed in Virginia.

In August 2012, Virginia Power filed with the North Carolina Commission an application for approval and its updated request for cost recovery for the five DSM programs approved in North Carolina, as well as cost recovery for projected costs of Commercial Lighting and Commercial Heating, Ventilating and Air Conditioning Upgrade programs on a North Carolina-only basis. In December 2012, the North Carolina Commission approved updated cost recovery for the five DSM programs, and requested an additional filing on whether the Commercial Lighting and the

14

Commercial Heating, Ventilating and Air Conditioning Upgrade programs will be offered on a North Carolina-only basis. Virginia Power made this additional filing in February 2013.

Virginia Power continues to evaluate opportunities to redesign current DSM programs and develop new DSM initiatives in Virginia and North Carolina.

Virginia Power is currently evaluating the effectiveness and benefits of installing AMI meters on homes and businesses throughout Virginia. The AMI meter demonstrations test the effectiveness of AMI meters in achieving voltage conservation, remotely turning off and on electric service, power outage and restoration detection and reporting, remote daily meter readings and offering dynamic rates. The AMI meter demonstrations are an on-going project that will help Virginia Power to further evaluate the technology and verify the potential impacts to its system.

Renewable Generation

Renewable energy is also an important component of a diverse and reliable energy mix. Both Virginia and North Carolina have passed legislation setting targets for renewable power. Virginia Power is committed to meeting Virginia’s goals of 12% of base year electric energy sales from renewable power sources by 2022, and 15% by 2025, and North Carolina’s RPS of 12.5% by 2021. In May 2010, the Virginia Commission approved Virginia Power’s participation in the state’s RPS program. As a participant, Virginia Power is permitted to seek recovery, through rate adjustment clauses, of the costs of programs designed to meet RPS goals. Virginia Power plans to meet the respective RPS targets in Virginia and North Carolina by utilizing existing renewable facilities, as well as through additional renewable generation. In addition, Virginia Power intends to purchase renewable energy certificates, as permitted by each RPS program, to help meet any remaining annual requirement needs, as well as to fund renewable energy research and development initiatives at Virginia institutions of higher education. Virginia Power continues to explore opportunities to develop new renewable facilities within its service territory, the energy attributes of which would potentially qualify for inclusion in the RPS programs. Virginia Power is converting three coal-fired Virginia generating power stations to biomass, which will increase Dominion’s renewable generation by more than 150 MW. The conversions are expected to be completed by the end of 2013. In November 2012, the Virginia Commission approved a voluntary demonstration program for Company-owned solar distributed generation facilities, to be located at selected commercial, industrial and community locations throughout its Virginia service territory.

Dominion has invested in wind energy through two joint ventures. Dominion is a 50% owner with Shell of NedPower. Dominion’s share of this project produces 132 MW of renewable energy. Dominion is also a 50% owner with BP of the first phase of Fowler Ridge, which has a generating capacity of 300 MW. Dominion has a long-term agreement with Fowler Ridge to purchase 200 MW of energy, capacity and environmental attributes from this first phase.

See Note 13 to the Consolidated Financial Statements for additional information.

Other Generation Development

Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new

multi-fuel, multi-technology generation capacity to meet the anticipated growth in demand in its core market of Virginia. Virginia Power expects that these investments collectively will provide the following benefits: expanded electricity production capability, increased technological and fuel diversity and a reduction in the CO₂ emission intensity of its generation fleet.

Improvements in Other Energy Infrastructure

Virginia Power’s five-year investment plan includes significant capital expenditures to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service, and are intended to address both continued population growth and increases in electricity consumption by the typical consumer. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed or to be developed in the future.

Virginia Power is taking measures to ensure that its electrical infrastructure can support the expected demand from electric vehicles, which have significantly lower carbon intensity than conventional vehicles. Virginia Power has partnered with Ford Motor Company to help prepare Virginia for the operation of electric vehicles, in a collaboration that involves consumer outreach, educational programs and the exchange of information on vehicle charging requirements. In July 2011, the Virginia Commission approved Virginia Power’s application to establish an Electric Vehicle Pilot Program, including two experimental and voluntary electric vehicle rate options.

Dominion, in connection with its five-year growth plan, is also pursuing the construction or upgrade of regulated infrastructure in its natural gas business.

Dominion and Virginia Power’s Strategy for Voluntarily Reducing GHG Emissions

While Dominion and Virginia Power have not established a standalone GHG emissions reduction target or timetable, they are actively engaged in voluntary reduction efforts, as well as working toward achieving required RPS standards established by existing state regulations, as set forth above. The Companies have an integrated voluntary strategy for reducing overall GHG emission intensity that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, oil, hydro and renewable energy, investing in renewable energy projects and promoting energy conservation and efficiency efforts. Below are some of the Companies’ efforts that have or are expected to reduce the Companies’ overall carbon emissions or intensity:

Ÿ Since 2000, Dominion has added approximately 3,300 MW of non-emitting generation and over 5,000 MW of lower-emitting natural gas-fired generation, including over 3,000 MW at Virginia Power, to its generation mix.

Ÿ Virginia Power added 83 MW of renewable biomass and is converting three coal-fired power stations to biomass, which is anticipated to be considered carbon neutral by regulatory agencies.

Ÿ Virginia Power has requested approval from the Virginia Commission to convert Bremo Units 3 and 4 from coal to natural gas.

15

Ÿ Dominion has over 800 MW of wind energy in operation or development.

Ÿ Virginia Power is constructing the natural gas-fired Warren County power station.

Ÿ Virginia Power has filed an application with the Virginia Commission for approval to construct an additional combined-cycle natural gas-fired power station and related transmission interconnection facilities in Brunswick County.

Ÿ Virginia Power has stated that coal-fired units at Chesapeake and Yorktown are planned to be retired by 2015.

Ÿ Virginia Power has received an Early Site Permit from the NRC for the possible addition of approximately 1,500 MW of nuclear generation in Virginia. Virginia Power has not yet committed to building a new nuclear unit.

Ÿ Virginia Power has developed and implemented the DSM programs described above.

Ÿ Virginia Power has initiated a demonstration of smart grid technologies as described above.

Ÿ In October 2011, Virginia Power announced plans to develop a community solar power program.

Ÿ In 2012, Dominion sold Salem Harbor and State Line, two coal-and fuel oil-fired facilities.

Ÿ In the third quarter of 2012, Dominion announced its intention to pursue the sale of its coal-fired merchant power stations, Brayton Point and Kincaid.

Ÿ In December 2012, Dominion announced its plans to develop a 15 MW fuel cell power generating facility in Bridgeport, Connecticut.

While Virginia Power’s new Virginia City Hybrid Energy Center, which started commercial operations in July 2012, is a new source of GHG emissions, Virginia Power has taken steps to minimize the impact on the environment. The new plant is expected to use at least 10% biomass for fuel and is designed to be carbon-capture compatible, meaning that technology to capture CO₂ can be added to the station if or when it becomes commercially available. It is currently estimated that the Virginia City Hybrid Energy Center will have the potential to emit about 4.8 million metric tonnes of direct CO₂ emissions in a year assuming a 100% capacity factor and 100% coal-fired operation. Actual emissions will depend on the capacity factor of the facility and the extent to which biomass is burned.

Dominion also developed a comprehensive GHG inventory for calendar year 2011. For Dominion Generation, Dominion’s and Virginia Power’s direct CO₂ equivalent emissions, based on equity share (ownership), were approximately 42.1 million metric tonnes and 25.9 million metric tonnes, respectively, in 2011. The decrease in emissions from 2010 to 2011 is proportional to a decrease in generated MW, due mainly to lower demand and milder weather in 2011. For the DVP operating segment’s electric transmission and distribution operations, direct CO₂ equivalent emissions for 2011 stayed the same as in 2010 at 0.2 million metric tonnes. For 2011, DTI’s (including Cove Point) direct CO₂ equivalent emissions were approximately 1.2 million metric tonnes and East Ohio’s direct CO₂ equivalent emissions were approximately 1.1 million metric tonnes. The emissions appear to have decreased significantly compared to previous year’s inventories. These differences may not be comparable, however, due to a change in calculation methodologies required under the

EPA Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98. Dominion’s GHG inventory now follows all methodologies specified in the EPA Mandatory Greenhouse Gas Reporting Rule, 40 CFR Part 98 for calculating emissions.

Since 2000, the Companies have tracked the emissions of their electric generation fleet. Their electric generation fleet employs a mix of fuel and renewable energy sources. Comparing annual year 2000 to annual year 2011, Dominion and Virginia Power’s electric generating fleet (based on ownership percentage) reduced their average CO₂ emissions rate per MWh of energy produced from electric generation by about 29% and 18%, respectively. During such time period, the capacity of Dominion and Virginia Power’s electric generation fleet has grown. The Companies do not yet have final 2012 emissions data.

Alternative Energy Initiatives

The AES department conducts research in the renewable and alternative energy technologies sector and supports strategic investments to advance Dominion’s degree of understanding of such technologies. AES participates in federal and state policy development on alternative energy and identifies potential alternative energy resource and technology opportunities for Dominion’s business units. For example, in December 2012, Virginia Power was selected by the DOE to begin negotiations for initial engineering, design and permitting work for a wind turbine demonstration facility approximately 24 miles off the coast of Virginia. The proposed 12 MW grid-connected facility would generate power via two turbines mounted on foundations driven into the ocean floor. In March 2011, Dominion issued a report evaluating high-voltage underwater transmission lines from Virginia Beach into the ocean to support multiple offshore wind farms; the first of many steps with the goal being the development of a transmission line making offshore wind resources available to its customers. A 2010 Dominion study of its existing transmission system in eastern Virginia showed that it is possible to interconnect large scale wind facilities up to an installed capability of 4,500 MW.

In 2012, Dominion continued to enhance and refine its EDGE^® grid-side efficiency product suite. EDGE^® is a modular and adaptive conservation voltage management solution enabling utilities to deploy incremental grid-side energy management that requires no behavioral changes or purchases by end customers. In February 2013, Dominion was awarded a patent relating to the EDGE^® technology.

REGULATION

Dominion and Virginia Power are subject to regulation by the Virginia Commission, North Carolina Commission, SEC, FERC, EPA, DOE, NRC, Army Corps of Engineers and other federal, state and local authorities.

16

State Regulations

ELECTRIC

Virginia Power’s electric utility retail service is subject to regulation by the Virginia Commission and the North Carolina Commission.

Virginia Power holds certificates of public convenience and necessity which authorize it to maintain and operate its electric facilities now in operation and to sell electricity to customers. However, Virginia Power may not construct generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies. In addition, the Virginia Commission and the North Carolina Commission regulate Virginia Power’s transactions with affiliates, transfers of certain facilities and the issuance of certain securities.

Electric Regulation in Virginia

The enactment of the Regulation Act in 2007 significantly changed electric service regulation in Virginia by instituting a modified cost-of-service rate model. With respect to most classes of customers, the Regulation Act ended Virginia’s planned transition to retail competition for its electric supply service. Base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. The Virginia Commission reviews Virginia Power’s base rates, terms and conditions for generation and distribution services on a biennial basis in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a combined two-year historic test period, and the determination of Virginia Power’s authorized ROE prospectively. If, as a result of the earnings test review, the Virginia Commission determines that Virginia Power’s historic earnings for the two-year test period are more than 50 basis points above the authorized level, 60% or 100% of earnings above this level must be shared with customers through a refund process. Under certain circumstances described in the Regulation Act, the Virginia Commission may also order a base rate increase or reduction during the biennial review. Circumstances where the Virginia Commission may order a base rate decrease include a determination by the Virginia Commission that Virginia Power has exceeded its authorized level of earnings by more than 50 basis points for two consecutive biennial review periods. Virginia Power’s authorized ROE can be set no lower than the average, for a three-year historic period, of the actual returns reported to the SEC by not less than a majority of comparable utilities within the Southeastern U.S., with certain limitations as described in the Regulation Act. Virginia Power’s ROE may be increased or decreased by up to 100 basis points based on operating performance criteria, or alternatively, will be increased by 50 basis points for compliance with Virginia’s RPS.

In addition, the Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation facilities or major unit modifications of existing facilities, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It provides for enhanced returns on capital expenditures relating to the construction or major modification of facilities that are nuclear-powered, clean coal/carbon capture compatible-powered, or renewable-powered, as well as conventional coal and combined-cycle combustion turbine facilities.

Costs of fuel used for the generation of electricity, along with costs of purchased power, are recovered from customers through an annually approved fuel rider, as provided under a separate section of the Virginia Code. Decisions of the Virginia Commission may be appealed to the Supreme Court of Virginia.

If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it could adversely affect its results of operations, financial condition and cash flows.

See Future Issues and Other Matters in Item 7. MD&A for changes to the Regulation Act enacted in 2013.

See Note 13 to the Consolidated Financial Statements for additional information.

Electric Regulation in North Carolina

Virginia Power’s retail electric base rates in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes and the rules and procedures of the North Carolina Commission. North Carolina base rates are set by a process that allows Virginia Power to recover its operating costs and an ROIC. If retail electric earnings exceed the authorized ROE established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery of costs incurred in providing service on a timely basis, Virginia Power’s future earnings could be negatively impacted. Fuel rates are subject to revision under annual fuel cost adjustment proceedings.

Virginia Power’s transmission service rates in North Carolina are regulated by the North Carolina Commission as part of Virginia Power’s bundled retail service to North Carolina customers.

In March 2012, Virginia Power filed an application with the North Carolina Commission to increase base non-fuel revenues with January 1, 2013 as the proposed effective date for the permanent rate revision. See Note 13 to the Consolidated Financial Statements for additional information.

GAS

Dominion’s gas distribution services are regulated by the Ohio Commission and the West Virginia Commission.

Status of Competitive Retail Gas Services

Both of the states in which Dominion has gas distribution operations have considered legislation regarding a competitive deregulation of natural gas sales at the retail level.

Ohio—Since October 2000, East Ohio has offered the Energy Choice program, under which residential and commercial customers are encouraged to purchase gas directly from retail suppliers or through a community aggregation program. In October 2006, East Ohio restructured its commodity service by entering into gas purchase contracts with selected suppliers at a fixed price above the NYMEX month-end settlement and passing that gas cost to customers under the Standard Service Offer program. Starting in April 2009, East Ohio buys natural gas under the Standard Service Offer program only for customers not eligible to participate in the Energy Choice program and places

17

Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills.

In January 2013, the Ohio Commission granted East Ohio’s motion to fully exit the merchant function for its nonresidential customers, beginning in April 2013, which will require those customers to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2012, approximately 1.0 million of Dominion’s 1.2 million Ohio customers were participating in the Energy Choice program. Subject to the Ohio Commission’s approval, East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. East Ohio continues to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.

West Virginia—At this time, West Virginia has not enacted legislation to require customers to choose in the retail natural gas markets served by Hope. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customers a choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.

Rates

Dominion’s gas distribution subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate—Ohio and West Virginia. When necessary, Dominion’s gas distribution subsidiaries seek general base rate increases to recover increased operating costs and a fair return on rate base investments. Base rates are set based on the cost of service by rate class. A straight-fixed-variable rate design, in which the majority of operating costs are recovered through a monthly charge rather than a volumetric charge, is utilized to establish rates for a majority of East Ohio’s customers pursuant to a 2008 rate case settlement. Base rates for Hope are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. In addition to general rate increases, Dominion’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery

through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective one-, three- or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses. The Ohio Commission has also approved several stand-alone cost recovery mechanisms to recover specified costs and a return for infrastructure projects and certain other costs that vary widely over time; such costs are excluded from general base rates. See Note 13 to the Consolidated Financial Statements for additional information.

Federal Regulations

FEDERAL ENERGY REGULATORY COMMISSION

Electric

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

Dominion and Virginia Power are subject to FERC’s Standards of Conduct that govern conduct between transmission function employees of interstate gas and electricity transmission providers and the marketing function employees of their affiliates. The rule defines the scope of transmission and marketing-related functions that are covered by the standards and is designed to prevent transmission providers from giving their affiliates undue preferences.

Dominion and Virginia Power are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between Virginia Power and Dominion’s merchant plants without first receiving FERC authorization, (2) require the merchant plants and Virginia Power to conduct their wholesale power sales operations separately, and (3) prohibit Virginia Power from sharing market information with merchant plant operating personnel. The rules are designed to prohibit Virginia Power from giving the merchant plants a competitive advantage.

EPACT included provisions to create an ERO. The ERO is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC has certified NERC as the ERO and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines of between $1 thousand and $1 million per day, and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.

Dominion and Virginia Power plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion and Virginia Power employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. Dominion and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cybersecurity programs as well as efforts to ensure appropriate facility ratings for Virginia Power’s transmission lines. In October 2010, NERC issued an industry alert identifying possible discrepancies between the design and actual field conditions of transmission facilities as a potential reliability issue. The alert recommends that entities review their current facilities rating methodology to verify that the methodology is based on actual field conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power is evaluating its transmission facilities for any discrepancies between design and

18

actual field conditions. In addition, NERC has requested the industry to increase the number of assets subject to NERC reliability standards that are designated as critical assets, including cybersecurity assets. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.

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

Gas

FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate natural gas company subsidiaries, including DTI and Cove Point. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

Dominion’s interstate gas transmission and storage activities are generally conducted on an open access basis, in accordance with certificates, tariffs and service agreements on file with FERC.

Dominion is also subject to the Pipeline Safety Acts of 2002 and 2011, which mandate inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those located in areas of high-density population. Dominion has evaluated its natural gas transmission and storage properties, as required by the Department of Transportation regulations under these Acts, and has implemented a program of identification, testing and potential remediation activities. These activities are ongoing.

See Future Issues and Other Matters in Item 7. MD&A and Note 13 to the Consolidated Financial Statements for additional information.

Environmental Regulations

Each of Dominion’s and Virginia Power’s operating segments faces substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Companies. If expenditures for pollution control technologies and associated operating costs are not recoverable from customers through regulated rates (in regulated jurisdictions) or market prices (in deregulated jurisdictions), those costs could adversely affect future results of operations and cash flows. Dominion and Virginia Power have applied for or obtained the necessary environmental permits for the operation of their facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned

capital expenditures relating to environmental compliance required to be discussed in this Item, see Environmental Matters in Future Issues and Other Matters in Item 7. MD&A, which information is incorporated herein by reference. Additional information can also be found in Item 3. Legal Proceedings and Note 22 to the Consolidated Financial Statements.

GLOBAL CLIMATE CHANGE

The national and international attention in recent years on GHG emissions and their relationship to climate change has resulted in federal, regional and state legislative or regulatory action in this area. Dominion and Virginia Power support national climate change legislation that would provide a consistent, economy-wide approach to addressing this issue and are currently taking action to protect the environment and address climate change while meeting the future needs of their growing service territory. Dominion’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including climate change, and Dominion’s Board of Directors receives periodic updates on these matters. See Environmental Strategy above, Environmental Matters in Future Issues and Other Matters in Item 7. MD&A and Note 22 to the Consolidated Financial Statements for information on climate change legislation and regulation, which information is incorporated herein by reference.

Nuclear Regulatory Commission

All aspects of the operation and maintenance of Dominion’s and Virginia Powers’ nuclear power stations are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.

From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining Dominion’s and Virginia Power’s nuclear generating units. See Nuclear Matters in Future Issues and Other Matters in Item 7 MD&A for further information.

The NRC also requires Dominion and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and the Companies are required by the NRC to be financially prepared. For information on decommissioning trusts, see Dominion Generation-Nuclear Decommissioning and Note 9 to the Consolidated Financial Statements. See Note 22 to the Consolidated Financial Statements for information on spent nuclear fuel.

CYBERSECURITY

In an effort to reduce the likelihood and severity of cyber intrusions, the Companies have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, Dominion and Virginia Power are subject to mandatory cybersecurity regulatory requirements, interface regularly with a wide range of external organizations, and participate in classified briefings to maintain an awareness of current cybersecurity threats and vulnerabilities. The Companies’ current security posture and regulatory compliance efforts are intended to address the evolving and changing cyber threats.

19

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 their control. A number of these factors have been identified below. 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 Item 7. MD&A.

Dominion’s and Virginia Power’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas, and affect the price of energy commodities. In addition, severe weather, including hurricanes and winter storms, can be destructive, causing outages and property damage that require incurring additional expenses. Changes in weather conditions can result in reduced water levels or changes in water temperatures that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level or sea temperatures.

The rates of Dominion’s gas transmission and distribution operations and Virginia Power’s electric transmission, distribution and generation operations are subject to regulatory review.Revenue provided by Virginia Power’s electric transmission, distribution and generation operations and Dominion’s gas transmission and distribution operations is based primarily on rates approved by state and federal regulatory agencies. The profitability of these businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.

Virginia Power’s wholesale rates for electric transmission service are adjusted on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism, Virginia Power’s wholesale electric transmission cost of service is estimated and thereafter adjusted to reflect Virginia Power’s actual electric transmission costs incurred. These wholesale rates are subject to FERC review and prospective adjustment in the event that customers and/or interested state commissions file a complaint with FERC and are able to demonstrate that Virginia Power’s wholesale revenue requirement is no longer just and reasonable.

Similarly, various rates and charges assessed by Dominion’s gas transmission businesses are subject to review by FERC. In addition, the rates of Dominion’s gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate.

Virginia Power’s base rates, terms and conditions for generation and distribution services to customers in Virginia are reviewed by the Virginia Commission on a biennial basis in a proceeding that involves the determination of Virginia Power’s actual earned ROE during a combined two-year historic test period, and the determination of Virginia Power’s authorized ROE prospectively. Under certain circumstances described in the Regulation Act, Virginia Power may be required to share a portion of its earnings with customers through a refund process, and the Virginia Commission may order a base rate increase or reduction during the biennial review. Additionally, Virginia

Power was required to discontinue deferral accounting for certain existing rate adjustment clauses as of December 1, 2011. As a result, Virginia Power may potentially not fully recover costs associated with these existing rate adjustment clauses.

Virginia Power’s retail electric base rates for bundled generation, transmission, and distribution services to customers in North Carolina are regulated on a cost-of-service/rate-of-return basis subject to North Carolina statutes, and the rules and procedures of the North Carolina Commission. If retail electric earnings exceed the returns established by the North Carolina Commission, retail electric rates may be subject to review and possible reduction by the North Carolina Commission, which may decrease Virginia Power’s future earnings. Additionally, if the North Carolina Commission does not allow recovery through base rates, on a timely basis, of costs incurred in providing service, Virginia Power’s future earnings could be negatively impacted.

Dominion and Virginia Power are subject to complex governmental regulation that could adversely affect their results of operations and subject the Companies to monetary penalties.Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. These operations are also subject to legislation governing taxation at the federal, state and local level. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that the business is conducted in accordance with applicable laws. The Companies’ businesses are subject to regulatory regimes which could result in substantial monetary penalties if either Dominion or Virginia Power is found not to be in compliance, including mandatory reliability standards and interaction in the wholesale markets. New laws or regulations, the revision or reinterpretation of existing laws or regulations, or penalties imposed for non-compliance with existing laws or regulations may result in substantial expense.

Dominion’s and Virginia Power’s generation business may be negatively affected by possible FERC actions that could change market design in the wholesale markets or affect pricing rules or revenue calculations in the RTO markets. Dominion’s and Virginia Power’s generation stations operating in RTO markets sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these generation stations to take advantage of market price opportunities, but also expose them to market risk. Properly functioning competitive wholesale markets depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize RTOs to make changes in market design. FERC also periodically reviews Dominion’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets, Dominion’s or Virginia Power’s authority to sell power at market-based rates, or changes to pricing rules or rules involving revenue calculations, could adversely impact the future results of Dominion’s or Virginia Power’s generation business.

Dominion and Virginia Power infrastructure build plans often require regulatory approval before construction can commence. Dominion and Virginia Power may not complete plant construction or expansion projects that they commence, or they may complete projects on materially different terms or timing than initially anticipated, and they may not be able to achieve the intended benefits of any such project, if completed.Several plant construction and expansion projects have been announced and additional projects may be considered in the

20

future. Commencing construction on announced plants requires approvals from applicable state and federal agencies. Projects may not be able to be completed on time as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of their counterparties or vendors, or other factors beyond their control. Even if plant construction and expansion projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of Dominion and Virginia Power following the projects may not meet expectations. Additionally, Dominion and Virginia Power may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Further, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Any of these or other factors could adversely affect the Companies’ ability to realize the anticipated benefits from the plant construction and expansion projects.

Dominion’s and Virginia Power’s current costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws, including laws and regulations designed to address global climate change, air quality, coal combustion by-products, cooling water and other matters could make certain of the Companies’ generation facilities uneconomical to maintain or operate.Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchase of allowances and/or offsets. Additionally, the Companies could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and Dominion and Virginia Power expect that they will remain significant in the future.

Existing environmental laws and regulations may be revised and/or new laws may be adopted or become applicable to Dominion or Virginia Power. The EPA is expected to issue additional regulations with respect to air quality under the CAA, including revised NAAQS and regulations governing the emissions of GHGs from electric generating units. Risks relating to potential regulation of GHG emissions are discussed below. Dominion and Virginia Power also expect additional federal water and waste regulations, including regulations concerning cooling water intake structures and coal combustion by-product handling and disposal practices that are expected to be applicable to at least some of its generating facilities.

Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new environmental rules or regulations. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liability on all responsible parties. However, such expenditures, if material, could make the Companies’ facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.

If additional federal and/or state requirements are imposed on energy companies mandating limitations on GHG emissions or requiring efficiency improvements, such requirements may result in compliance costs that alone or in combination could make some of Dominion’s or Virginia Power’s electric generation units or natural gas facilities uneconomical to maintain or operate.The EPA, environmental advocacy groups, other organizations and some state and other federal agencies are focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. Dominion and Virginia Power expect that additional EPA regulations, and possibly additional state legislation and/or regulations, may be issued resulting in the imposition of additional limitations on GHG emissions or requiring efficiency improvements from fossil fuel-fired electric generating units.

There are also potential impacts on Dominion’s natural gas businesses as federal or state GHG legislation or regulations may require GHG emission reductions from the natural gas sector and could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products. Several regions of the U.S. have moved forward with GHG emission regulations including regions where Dominion has operations. For example, Massachusetts and Rhode Island have implemented regulations requiring reductions in CO₂ emissions through RGGI, a cap and trade program covering CO₂ emissions from power plants in the Northeast, which affects several of Dominion’s facilities.

Compliance with GHG emission reduction requirements may require increasing the energy efficiency of equipment at facilities, committing significant capital toward carbon capture and storage technology, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower emitting generation facilities. The cost of compliance with GHG emission legislation and/or regulation is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon capture and storage technology, and the selected compliance alternatives. The Companies cannot estimate the aggregate effect of such requirements on their results of operations, financial condition or their customers. However, such expenditures, if material, could make the Companies’ generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.

Risks arising from the reliability of the Companies’ facilities supply chain disruptions or personnel issues could result in lost revenues andincreased expenses, including higher maintenance costs. Operation of the Companies’ facilities involves risk, including the risk of potential breakdown or failure of equipment or processes due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents, earthquakes and other natural disasters can disrupt operation of the Companies’ facilities. Because Virginia Power’s transmission facilities are interconnected with those of third parties, the operation of its facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

21

Operation of the Companies’ facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of the Companies’ facilities and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less output or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement output from third parties in the open market to satisfy forward energy and capacity or other contractual obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.

Dominion and Virginia Power have substantial ownership interests in and operate nuclear generating units; as a result, each may incur substantial costs and liabilities.Dominion’s and Virginia Power’s nuclear facilities are subject to operational, environmental, health and financial risks such as the on-site storage of spent nuclear fuel, the ability to dispose of such spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, limitations on the amounts and types of insurance available, potential operational liabilities and extended outages, the costs of replacement power, the costs of maintenance and the costs of securing the facilities against possible terrorist attacks. Dominion and Virginia Power maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that future decommissioning costs could exceed amounts in the decommissioning trusts and/or damages could exceed the amount of insurance coverage. If Dominion’s and Virginia Power’s decommissioning trust funds are insufficient, and they are not allowed to recover the additional costs incurred through insurance, or in the case of Virginia Power through regulatory mechanisms, their results of operations could be negatively impacted.

Dominion’s and Virginia Power’s nuclear facilities are also subject to complex government regulation which could negatively impact their results of operations. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit, or take some combination of these actions, depending on its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require Dominion and Virginia Power to make substantial expenditures at their nuclear plants. In addition, although the Companies have no reason to anticipate a serious nuclear incident at their plants, if an incident did occur, it could materially and adversely affect their results of operations and/or financial condition. A major incident at a nuclear facility anywhere in the world, such as the nuclear events in Japan in 2011, could cause the NRC to adopt increased safety regulations or otherwise limit or restrict the operation or licensing of domestic nuclear units.

Dominion depends on third parties to produce the natural gas it gathers and processes, and the NGLs it fractionates at its facilities. A reduction in these quantities could reduce Dominion’s revenues. Dominion obtains its supply of natural gas and NGLs from numerous third-party producers. Such producers are under no obligation to deliver a specific quantity of natural gas or NGLs to Dominion’s facilities, although the producers that have con-

tracted to supply natural gas to Dominion’s natural gas processing and fractionation facility under development in Natrium, West Virginia will generally be subject to contractual minimum fee payments. If producers were to decrease the supply of natural gas or NGLs to Dominion’s systems and facilities for any reason, Dominion could experience lower revenues to the extent it is unable to replace the lost volumes on similar terms.

Dominion’s merchant power business is operating in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion’s merchant power business depends upon favorable market conditions including the ability to sell power at prices sufficient to cover its operating costs. Dominion operates in active wholesale markets that expose it to price volatility for electricity and fuel as well as the credit risk of counterparties. Dominion attempts to manage its price risk by entering into hedging transactions, including short-term and long-term fixed price sales and purchase contracts.

In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently, the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore, changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion does not enter into long-term power purchase agreements or otherwise effectively hedge its output, these changes in market prices could adversely affect its financial results.

Dominion purchases fuel under a variety of terms, including long-term and short-term contracts and spot market purchases. Dominion is exposed to fuel cost volatility for the portion of its fuel obtained through short-term contracts or on the spot market, including as a result of market supply shortages. Fuel prices can be volatile and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs, thus adversely impacting Dominion’s financial results.

Energy conservation could negatively impact Dominion’s and Virginia Power’s financial results. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices, including lighting and electric heat pumps, could lead to declines in per capita energy consumption. To the extent conservation results in reduced energy demand or significantly slowed growth in demand, the value of the Companies’ business activities could be adversely impacted.

Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. Dominion and Virginia Power are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Counterparties could fail or delay the performance of their contractual obligations for a number of reasons, including the effect of regulations on their operations. Such defaults by customers, suppliers or other third parties may adversely affect the Companies’ financial results.

22

Market performance and other changes may decrease the value of decommissioning trust funds and benefit plan assets or increase Dominion’s liabilities, which could then require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trusts to satisfy future obligations to decommission Dominion’s nuclear plants and under its pension and other postretirement benefit plans. Dominion has significant obligations in these areas and holds significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates.

With respect to decommissioning trust funds, a decline in the market value of these assets may increase the funding requirements of the obligations to decommission Dominion’s nuclear plants or require additional NRC-approved funding assurance.

A decline in the market value of the assets held in trusts to satisfy future obligations under Dominion’s pension and other postretirement benefit plans may increase the funding requirements under such plans. Additionally, changes in interest rates affect the liabilities under Dominion’s pension and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension and other postretirement benefit plans.

If the decommissioning trust funds and benefit plan assets are negatively impacted by market fluctuations or other factors, Dominion’s results of operations, financial condition and/or cash flows could be negatively affected.

The use of derivative instruments could result in financial losses and liquidity constraints.Dominion and Virginia Power use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity and financial market risks. In addition, Dominion purchases and sells commodity-based contracts primarily in the natural gas market for trading purposes. The Companies could recognize financial losses on these contracts, including as a result of volatility in the market values of the underlying commodities, if a counterparty fails to perform under a contract or upon the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these transactions. In the absence of actively-quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the under-lying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

The use of derivatives to hedge future sales may limit the benefit Dominion would otherwise receive from increases in commodity prices. These hedge arrangements generally include collateral requirements that require Dominion to deposit funds or post letters of credit with counterparties, financial intermediaries or clearinghouses to cover the fair value of covered contracts in excess of agreed upon credit limits. For instance, when commodity prices rise to levels substantially higher than the levels where it has hedged future sales, Dominion may be required to use a material portion of its available liquidity or obtain additional liquidity to cover these collateral requirements. In some circumstances, this could have a compounding effect on Dominion’s financial liquidity and results of operations. In addition, the availability or security of the collateral delivered by Dominion

may be adversely affected by the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear these types of transactions.

Derivatives designated under hedge accounting, to the extent not fully offset by the hedged transaction, can result in ineffectiveness losses. These losses primarily result from differences between the location and/or specifications of the derivative hedging instrument and the hedged item and could adversely affect Dominion’s results of operations.

Dominion’s and Virginia Power’s operations in regards to these transactions are subject to multiple market risks including market liquidity, price volatility, credit strength of the Companies’ counterparties and the financial condition of the financial intermediaries, exchanges and clearinghouses used for the types of transactions. These market risks are beyond the Companies’ control and could adversely affect their results of operations, liquidity and future growth.

The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The Dodd-Frank Act includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can choose to exempt their hedging transactions from these clearing and exchange trading requirements. Final rules for the over-the-counter derivative-related provisions of the Dodd-Frank Act will continue to be established through the ongoing rulemaking process of the applicable regulators. If, as a result of the rulemaking process, Dominion’s or Virginia Power’s derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs, including from higher margin requirements, for their derivative activities. In addition, implementation of, and compliance with, the over-the-counter derivative provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in increased costs related to the Companies’ derivative activities.

Changing rating agency requirements could negatively affect Dominion’s and Virginia Power’s growth and business strategy. In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency requirements, Dominion and Virginia Power may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in Dominion’s credit ratings or the credit ratings of Virginia Power could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require Dominion to post additional collateral in connection with some of its price risk management activities.

An inability to access financial markets could adversely affect the execution of Dominion’s and Virginia Power’s business plans. Dominion and Virginia Power rely on access to short-term money markets and longer-term capital markets as significant sources of funding and liquidity for capital expenditures, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or declines in market reputation either for the Companies or their industry in general, or general financial market disruptions outside of Dominion’s and Virginia Power’s control could increase their cost of borrowing or restrict their

23

ability to access one or more financial markets. Further market disruptions could stem from delays in the current economic recovery, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, or the failure of financial institutions on which the Companies rely. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to affect their ability to execute their business plans as scheduled.

Potential changes in accounting practices may adversely affect Dominion’s and Virginia Power’s financial results. Dominion and Virginia Power cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or their operations specifically. New accounting standards could be issued that could change the way they record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect earnings or could increase liabilities.

War, acts and threats of terrorism, natural disaster and other significant events could adversely affect Dominion’s and Virginia Power’s operations. Dominion and Virginia Power cannot predict the impact that any future terrorist attacks may have on the energy industry in general, or on the Companies’ business in particular. Any retaliatory military strikes or sustained military campaign may affect the Companies’ operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets. In addition, the Companies’ infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Furthermore, the physical compromise of the Companies’ facilities could adversely affect the Companies’ ability to manage these facilities effectively. Instability in financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy and increase the cost of insurance coverage. This could negatively impact the Companies’ results of operations and financial condition.

Hostile cyber intrusions could severely impair Dominion’s and Virginia Power’s operations, lead to the disclosure of confidential information, damage the reputation of the Companies and otherwise have an adverse effect on Dominion’s and Virginia Power’s business. The Companies own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run the Companies’ facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or the Companies’ operations could view the Companies’ computer systems, software or networks as attractive targets for cyber attack. In addition, the Companies’ businesses require that they collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

A successful cyber attack on the systems that control the Companies’ electric generation, electric or gas transmission or distribution assets could severely disrupt business operations, preventing the Companies from serving customers or collecting revenues. The breach of certain business systems could affect the Companies’ ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to the Companies’ reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other

confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. The Companies maintain property and casualty insurance that may cover certain damage caused by potential cybersecurity incidents, however, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could materially and adversely affect the Companies’ business, financial condition and results of operations.

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on Dominion’s and Virginia Power’s operations. Dominion’s and Virginia Power’s business strategy is dependent on their ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect their business and future operating results. An aging workforce in the energy industry necessitates recruiting, retaining and developing the next generation of leadership.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

As of December 31, 2012, Dominion owned its principal executive office and three other corporate offices, all located in Richmond, Virginia. Dominion also leases corporate offices in other cities in which its subsidiaries operate. Virginia Power shares its principal office in Richmond, Virginia, which is owned by Dominion. In addition, Virginia Power’s DVP and Generation segments share certain leased buildings and equipment. See Item 1. Business for additional information about each segment’s principal properties, which information is incorporated herein by reference.

Dominion’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described here and in Item 1. Business.

Substantially all of Virginia Power’s property is subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2012; however, by leaving the indenture open, Virginia Power retains the flexibility to issue mortgage bonds in the future. Certain of Dominion’s merchant generation facilities are also subject to liens. See Item 7. MD&A for more information.

POWER GENERATION

Dominion and Virginia Power generate electricity for sale on a wholesale and a retail level. The Companies supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2012, Dominion Generation’s total utility and merchant generating capacity was approximately 27,500 MW.

24

The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2012:

VIRGINIA POWER UTILITY GENERATION

Plant	Location	Net Summer Capability (MW)			Percentage Net Summer Capability
Coal
Mt. Storm	Mt. Storm, WV		1,599
Chesterfield	Chester, VA		1,267
Virginia City Hybrid Energy Center	Wise County, VA		600
Chesapeake(1)	Chesapeake, VA		595
Clover	Clover, VA		433	(5)
Yorktown(1)	Yorktown, VA		323
Bremo(2)	Bremo Bluff, VA		227
Mecklenburg	Clarksville, VA		138
Altavista(3),(4)	Altavista, VA		63
Hopewell(4)	Hopewell, VA		63
Southampton(4)	Southampton, VA		63
Total Coal			5,371			28	%
Gas
Ladysmith (CT)	Ladysmith, VA		783
Remington (CT)	Remington, VA		608
Bear Garden (CC)	Buckingham County, VA		590
Possum Point (CC)	Dumfries, VA		559
Chesterfield (CC)	Chester, VA		397
Elizabeth River (CT)	Chesapeake, VA		348
Possum Point	Dumfries, VA		316
Bellemeade (CC)	Richmond, VA		267
Gordonsville Energy (CC)	Gordonsville, VA		218
Gravel Neck (CT)	Surry, VA		170
Darbytown (CT)	Richmond, VA		168
Rosemary (CC)	Roanoke Rapids, NC		165
Total Gas			4,589			23
Nuclear
Surry	Surry, VA		1,678
North Anna	Mineral, VA		1,668	(6)
Total Nuclear			3,346			17
Oil
Yorktown	Yorktown, VA		818
Possum Point	Dumfries, VA		786
Gravel Neck (CT)	Surry, VA		198
Darbytown (CT)	Richmond, VA		168
Possum Point (CT)	Dumfries, VA		72
Chesapeake (CT)	Chesapeake, VA		51
Low Moor (CT)	Covington, VA		48
Northern Neck (CT)	Lively, VA		47
Total Oil			2,188			11
Hydro
Bath County	Warm Springs, VA		1,802	(7)
Gaston	Roanoke Rapids, NC		220
Roanoke Rapids	Roanoke Rapids, NC		95
Other	Various		3
Total Hydro			2,120			11
Biomass
Pittsylvania	Hurt, VA		83			—
Various
Other	Various		11			—
			17,708
Power Purchase Agreements			1,887			10
Total Utility Generation			19,595			100	%

Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.

(1) Certain coal-fired units are expected to be retired at Chesapeake and Yorktown by 2015 as a result of the issuance of the MATS rule.

(2) Planned to convert to gas subject to necessary regulatory approvals.

(3) Facility has been placed into cold reserve status, but can be restarted within a reasonably short period if necessary.

(4) In the first quarter of 2012, the facility received regulatory approval to convert to biomass.

25

(5) Excludes 50% undivided interest owned by ODEC.

(6) Excludes 11.6% undivided interest owned by ODEC.

(7) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.

DOMINION MERCHANT GENERATION

Plant	Location	Net Summer Capability (MW)			Percentage Net Summer Capability
Nuclear
Millstone	Waterford, CT		2,016	(5)
Kewaunee(1)	Kewaunee, WI		556
Total Nuclear			2,572			33	%
Gas
Fairless (CC)(2),(3)	Fairless Hills, PA		1,196
Elwood (CT)(2),(4)	Elwood, IL		712	(6)
Manchester (CC)	Providence, RI		432
Total Gas			2,340			30
Coal
Kincaid(2),(4)	Kincaid, IL		1,158
Brayton Point(4)	Somerset, MA		1,083
Total Coal			2,241			28
Oil
Brayton Point(4)	Somerset, MA		435
Total Oil			435			6
Wind
Fowler Ridge(2)	Benton County, IN		150	(7)
NedPower Mt. Storm(2)	Grant County, WV		132	(8)
Total Wind			282			3
Various
Brayton Point(4),(9)	Somerset, MA		10			—
Total Merchant Generation			7,880			100	%

Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.

(1) In the fourth quarter of 2012, Dominion announced that it would permanently cease operations at Kewaunee in 2013 and commence decommissioning of this facility.

(2) Subject to a lien securing the facility’s debt. Also see Note 17 to the Consolidated Financial Statements for additional information on liens related to Kincaid and Fairless.

(3) Includes generating units that Dominion operates under leasing arrangements.

(4) In the third quarter of 2012, Dominion announced its decision to pursue the sale of Brayton Point, Kincaid and its 50% interest in Elwood.

(5) Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and Green Mountain Power Corporation.

(6) Excludes 50% membership interest owned by J-POWER Elwood, LLC.

(7) Excludes 50% membership interest owned by BP.

(8) Excludes 50% membership interest owned by Shell.

(9) Represents four diesel generators.

26

Item 3. 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.

In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, NSPS, and 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. In May 2010, 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 Brayton Point. Dominion submitted its response to the request in November 2010.

Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. The CAA authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation at each generating unit, depending on the date of the alleged violation. In addition to any such penalties that may be awarded, an adverse outcome could require substantial capital expenditures or affect the timing of currently budgeted capital expenditures. Dominion is currently in settlement discussions to resolve these matters. However, there can be no assurance that Dominion will reach a settlement with the EPA. Dominion does not believe that final resolution of the matter will have a material adverse effect on its results of operations, financial condition or cash flows.

See Notes 13 and 22 to the Consolidated Financial Statements and Future Issues and Other Matters in MD&A, which information is incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which the Companies are a party.

Item 4. Mine Safety Disclosures

Not applicable.

27

Executive Officers of Dominion

Information concerning the executive officers of Dominion, each of whom is elected annually, is as follows:

Name and Age	Business Experience Past Five Years(1)
Thomas F. Farrell II (58)	Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date; Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date.
Mark F. McGettrick (55)	Executive Vice President and CFO of Dominion and Virginia Power from June 2009 to date; Executive Vice President of Dominion from April 2006 to May 2009; President and COO-Generation of Virginia Power from February 2006 to May 2009.
Paul D. Koonce (53)	Executive Vice President and Chief Executive Officer – Energy Infrastructure Group of Dominion from February 2013 to date; President and COO of Virginia Power from June 2009 to date; Executive Vice President of Dominion from April 2006 to February 2013.
David A. Christian (58)	Executive Vice President and Chief Executive Officer – Dominion Generation Group of Dominion from February 2013 to date; President and COO of Virginia Power from June 2009 to date; Executive Vice President of Dominion from May 2011 to February 2013; President and CNO of Virginia Power from October 2007 to May 2009.
David A. Heacock (55)	President and CNO of Virginia Power from June 2009 to date; Senior Vice President of Dominion and President and COO-DVP of Virginia Power from June 2008 to May 2009; Senior Vice President-DVP of Virginia Power from October 2007 to May 2008.
Gary L. Sypolt (59)	Executive Vice President of Dominion from May 2011 to date; President of DTI from June 2009 to date; President-Transmission of DTI from January 2003 to May 2009.
Robert M. Blue (45)	Senior Vice President-Law, Public Policy and Environment of Dominion and Virginia Power from January 2011 to date; Senior Vice President-Public Policy and Environment of Dominion from February 2010 to December 2010; Senior Vice President-Public Policy and Corporate Communications of Dominion from May 2008 to January 2010; Vice President-State and Federal Affairs of DRS from September 2006 to May 2008.
Steven A. Rogers (51)(2)	Senior Vice President and Chief Administrative Officer of Dominion from October 2007 to December 2012; Senior Vice President and CAO of Dominion and Virginia Power from January 2007 to September 2007 and CNG from January 2007 to June 2007.
Ashwini Sawhney (63)	Vice President-Accounting and Controller (CAO) of Dominion from May 2010 to date; Vice President and Controller (CAO) of Dominion from July 2009 to May 2010; Vice President-Accounting of Virginia Power from April 2006 to date; Vice President and Controller of Dominion from April 2007 to June 2009.

(1) Any service listed for Virginia Power, DTI and DRS reflects service at a subsidiary of Dominion.

(2) Steven A. Rogers ceased to be an executive officer of Dominion as of January 1, 2013.

28

Part II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Dominion

Dominion’s common stock is listed on the NYSE. At January 31, 2013, there were approximately 139,000 record holders of Dominion’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion Direct. Discussions of expected dividend payments and restrictions on Dominion’s payment of dividends required by this Item are contained in Liquidity and Capital Resources in Item 7. MD&A and Notes 17 and 20 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 2012 and 2011. Quarterly information concerning stock prices and dividends is disclosed in Note 26 to the Consolidated Financial Statements, which information is incorporated herein by reference.

The following table presents certain information with respect to Dominion’s common stock repurchases during the fourth quarter of 2012:

DOMINION PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares (or Units) Purchased(1)		Average Price Paid per Share (or Unit)(2)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(3)
10/1/2012-10/31/12		467	$	52.81		N/A	19,629,059 shares/$	1.18 billion
11/1/2012-11/30/12		—	$	—		N/A	19,629,059 shares/$	1.18 billion
12/1/2012-12/31/12		—	$	—		N/A	19,629,059 shares/$	1.18 billion
Total		467	$	52.81		N/A	19,629,059 shares/$	1.18 billion

(1) In October 2012, 467 shares were tendered by employees to satisfy tax withholding obligations on vested restricted stock.

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

(3) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion 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.

Virginia Power

There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion. Restrictions on Virginia Power’s payment of dividends are discussed in Dividend Restrictions in Item 7. MD&A and Note 20 to the Consolidated Financial Statements. Virginia Power paid quarterly cash dividends on its common stock as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Full Year
(millions)
2012	$	149	$	120	$	110	$	180	$	559
2011		131		118		199		109		557

29

Item 6. Selected Financial Data

DOMINION

Year Ended December 31,	2012			2011			2010			2009		2008
(millions, except per share amounts)
Operating revenue	$	13,093		$	14,145		$	14,927		$	14,575	$	15,594
Income from continuing operations, net of tax(1)		324			1,433			3,066			1,276		1,599
Income (loss) from discontinued operations, net of tax(1)		(22	)		(25	)		(258	)		11		235
Net income attributable to Dominion		302			1,408			2,808			1,287		1,834
Income from continuing operations before loss from discontinued operations per common share-basic		0.57			2.50			5.21			2.15		2.76
Net income attributable to Dominion per common share-basic		0.53			2.46			4.77			2.17		3.17
Income from continuing operations before loss from discontinued operations per common share-diluted		0.57			2.49			5.20			2.15		2.75
Net income attributable to Dominion per common share-diluted		0.53			2.45			4.76			2.17		3.16
Dividends declared per common share		2.11			1.97			1.83			1.75		1.58
Total assets		46,838			45,614			42,817			42,554		42,053
Long-term debt		16,851			17,394			15,758			15,481		14,956

(1) Amounts attributable to Dominion’s common shareholders.

2012 results include a $1.0 billion after-tax impairment charge due to bids received for Brayton Point and Kincaid and a $303 million after-tax charge primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013.

2011 results include a $139 million after-tax charge reflecting generation plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units and a $59 million after-tax charge reflecting restoration costs associated with damage caused by Hurricane Irene.

2010 results include a $1.4 billion after-tax net income benefit from the sale of substantially all of Dominion’s Appalachian E&P operations, net of charges related to the divestiture and a $202 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, as discussed in Notes 3 and 22 to the Consolidated Financial Statements, respectively. The loss from discontinued operations in 2010 includes $127 million of after-tax impairment charges at certain merchant generation facilities and a $140 million after-tax loss on the sale of Peoples.

2009 results include a $435 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings. Also in 2009, Dominion recorded a $281 million after-tax ceiling test impairment charge related to the carrying value of its Appalachian E&P properties.

2008 results include $109 million of after-tax charges reflecting other-than-temporary declines in the fair value of certain securities held as investments in nuclear decommissioning trusts. In addition, income from discontinued operations in 2008 includes a $120 million after-tax benefit due to the reversal of deferred tax liabilities associated with the sale of Peoples.

VIRGINIA POWER

Year Ended December 31,	2012		2011		2010		2009		2008
(millions)
Operating revenue	$	7,226	$	7,246	$	7,219	$	6,584	$	6,934
Net income		1,050		822		852		356		864
Balance available for common stock		1,034		805		835		339		847
Total assets		24,811		23,544		22,262		20,118		18,802
Long-term debt		6,251		6,246		6,702		6,213		6,000

2012 results include a $53 million after-tax charge reflecting restoration costs associated with damage caused by severe storms.

2011 results include a $139 million after-tax charge reflecting generation plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired generating units and a $59 million after-tax charge reflecting restoration costs associated with damage caused by Hurricane Irene.

2010 results include a $123 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, discussed in Note 22 to the Consolidated Financial Statements.

2009 results include a $427 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings.

30

Item 7. 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 Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data.

CONTENTS OF MD&A

MD&A consists of the following information:

Ÿ Forward-Looking Statements

Ÿ Accounting Matters

Ÿ Dominion

Ÿ Results of Operations

Ÿ Segment Results of Operations

Ÿ Virginia Power

Ÿ Results of Operations

Ÿ Segment Results of Operations

Ÿ Selected Information—Energy Trading Activities

Ÿ Liquidity and Capital Resources

Ÿ 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,” “continue,” “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:

Ÿ Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;

Ÿ Extreme weather events and other natural disasters, including hurricanes, high winds, severe storms, earthquakes and changes in water temperature and availability that can cause outages and property damage to facilities;

Ÿ Federal, state and local legislative and regulatory developments;

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

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

Ÿ 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;

Ÿ Unplanned outages of the Companies’ facilities;

Ÿ 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;

Ÿ Counterparty credit and performance risk;

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

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

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

Ÿ Fluctuations in interest rates;

Ÿ Changes in federal and state tax laws and regulations;

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

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

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

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

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

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

Ÿ 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;

Ÿ Political and economic conditions, including inflation and deflation;

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

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

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

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

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

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

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

Ÿ Adverse outcomes in litigation matters or regulatory proceedings.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.

31

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

Dominion and Virginia Power have identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to their financial condition or results of operations under different conditions or using different assumptions. Dominion and Virginia Power have discussed the development, selection and disclosure of each of these policies with the Audit Committees of their Boards of Directors. Virginia Power’s Board of Directors also serves as its Audit Committee.

ACCOUNTING FOR REGULATED OPERATIONS

The accounting for Virginia Power’s regulated electric and Dominion’s regulated gas operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs are deferred as regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. See Notes 12 and 13 to the Consolidated Financial Statements for additional information.

ASSET RETIREMENT OBLIGATIONS

Dominion and Virginia Power recognize liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists and the ARO can be reasonably estimated. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, the Companies estimate the fair value of their AROs using present value techniques, in which they make various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. The impact on measurements of new AROs or remeasurements of existing AROs, using different cost escalation rates in the future, may be significant. When the Companies revise any assumptions used to calculate the fair value of existing AROs, they adjust the carrying amount of both the ARO liability and the related long-lived asset. The Companies accrete the ARO liability to reflect the passage of time.

In 2012, 2011 and 2010, Dominion recognized $77 million, $84 million and $85 million, respectively, of accretion, and expects to recognize $88 million in 2013. In 2012, 2011 and 2010, Virginia Power recognized $34 million, $36 million and $35 million, respectively, of accretion, and expects to recognize $38 million in 2013. Virginia Power records accretion and depreciation associated with utility nuclear decommissioning AROs as an adjustment to its regulatory liability for nuclear decommissioning.

A significant portion of the Companies’ AROs relates to the future decommissioning of Dominion’s merchant and Virginia Power’s utility nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2012, Dominion’s nuclear decommissioning AROs totaled $1.5 billion, representing approximately 86% of its total AROs. At December 31, 2012, Virginia Power’s nuclear decommissioning AROs totaled $633 million, representing approximately 90% of its total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with the Companies’ nuclear decommissioning obligations.

The Companies obtain from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for their nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. In addition, the Companies’ cost estimates include cost escalation rates that are applied to the base year costs. The Companies determine cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. The selection of these cost escalation rates is dependent on subjective factors which are considered to be a critical assumption.

In September 2012, Dominion recorded an increase of $246 million in the nuclear decommissioning AROs for its units. The ARO revision was primarily driven by management’s decision to cease operations and begin decommissioning Kewaunee in 2013. Virginia Power recorded an increase of $43 million in the nuclear decommissioning AROs for its units. The ARO revision was driven by an increase in estimated costs. In December 2011, Dominion recorded a decrease of $290 million in the nuclear decommissioning AROs for its units. Virginia Power recorded a decrease of $95 million in the nuclear decommissioning AROs for its units. The ARO revision in 2011 was driven by a reduction in anticipated future decommissioning costs due to the expected future recovery from the DOE of certain spent fuel costs based on the Companies’ contracts with the DOE for disposal of spent nuclear fuel, as well as updated escalation rates.

INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

32

Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2012, Dominion had $293 million and Virginia Power had $57 million of unrecognized tax benefits.

Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power evaluate quarterly the probability of realizing deferred tax assets by considering current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. The Companies establish a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2012, Dominion had established $93 million of valuation allowances and Virginia Power had no valuation allowances.

ACCOUNTING FOR DERIVATIVE CONTRACTS AND OTHER INSTRUMENTS AT FAIR VALUE

Dominion and Virginia Power use derivative contracts such as futures, swaps, forwards, options and FTRs to manage commodity and financial market risks of their business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies. The majority of investments held in Dominion’s and Virginia Power’s nuclear decommissioning and Dominion’s rabbi and benefit plan trust funds are also subject to fair value accounting. See Notes 6 and 21 to the Consolidated Financial Statements for further information on these fair value measurements.

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, the Companies consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases, the Companies must estimate prices based on available historical and near-term future price information and use of statistical methods, including regression analysis, that reflect their market assumptions.

The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

As of December 31, 2012, Dominion reported $3.1 billion of goodwill in its Consolidated Balance Sheet. A significant portion resulted from the acquisition of the former CNG in 2000.

In April of each year, Dominion tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2012, 2011 and 2010 annual tests and any interim tests did not result in the recognition of any goodwill impairment.

In general, Dominion estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. For Dominion’s Appalachian E&P operations and Peoples and Hope operations, negotiated sales prices were used as fair value for the tests conducted in 2010. Fair value estimates are dependent on subjective factors such as Dominion’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present. See Note 11 to the Consolidated Financial Statements for additional information.

USE OF ESTIMATES IN LONG-LIVED ASSET IMPAIRMENT TESTING

Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing, expectations about operating the long-lived assets and the

33

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

selection of an appropriate discount rate. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset, including future production and sales levels, expected fluctuations of prices of commodities sold and consumed and expected proceeds from dispositions. See Note 6 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets.

EMPLOYEE BENEFIT PLANS

Dominion sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit obligations and the anticipated rate of increase in healthcare costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between Dominion’s assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.

The expected long-term rates of return on plan assets, discount rates and healthcare cost trend rates are critical assumptions. Dominion determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:

Ÿ Expected inflation and risk-free interest rate assumptions;

Ÿ Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;

Ÿ Expected future risk premiums, asset volatilities and correlations;

Ÿ Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; and

Ÿ Investment allocation of plan assets. The strategic target asset allocation for Dominion’s pension funds is 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments, such as private equity investments.

Strategic investment policies are established for Dominion’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include those mentioned above such as employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/

liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns.

Dominion develops assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions. Dominion calculated its pension cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2012, 2011 and 2010. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 7.75% for 2012, 2011 and 2010. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets.

Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost were 5.50% in 2012, 5.90% in 2011 and 6.60% in 2010. Dominion selected a discount rate of 4.40% for determining its December 31, 2012 projected pension and other postretirement benefit obligations.

Dominion establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected, and demographics of plan participants. Dominion’s healthcare cost trend rate assumption as of December 31, 2012 was 7% and is expected to gradually decrease to 4.60% by 2061 and continue at that rate for years thereafter.

The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed, while holding all other assumptions constant:

				Increase in Net Periodic Cost
	Change in Actuarial Assumption			Pension Benefits		Other Postretirement Benefits
(millions, except percentages)
Discount rate		(0.25	)%	$	17	$	4
Long-term rate of return on plan assets		(0.25	)%		13		3
Healthcare cost trend rate		1	%		N/A		17

In addition to the effects on cost, at December 31, 2012, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $219 million and its accumulated postretirement benefit obligation by $54 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $218 million. See Note 21 to the Consolidated Financial Statements for additional information.

REVENUE RECOGNITION—UNBILLED REVENUE

Virginia Power recognizes and records revenues when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, the amount of electric energy delivered to customers, but not yet billed, is estimated and recorded as unbilled revenue. This estimate is reversed in the following month and actual revenue is recorded based on meter readings. Virginia

34

Power’s customer receivables included $348 million and $360 million of accrued unbilled revenue at December 31, 2012 and 2011, respectively.

The calculation of unbilled revenues is complex and includes numerous estimates and assumptions including historical usage, applicable customer rates, weather factors and total daily electric generation supplied, adjusted for line losses. Changes in customer usage patterns and other factors, which are the basis for the estimates of unbilled revenues, could have a significant effect on the calculation and therefore on Virginia Power’s results of operations and financial condition.

DOMINION

RESULTS OF OPERATIONS

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

Year Ended December 31,	2012		$ Change			2011		$ Change			2010
(millions, except EPS)
Net Income attributable to Dominion	$	302	$	(1,106	)	$	1,408	$	(1,400	)	$	2,808
Diluted EPS		0.53		(1.92	)		2.45		(2.31	)		4.76

Overview

2012 VS. 2011

Net income attributable to Dominion decreased by 79%. Unfavorable drivers include impairment and other charges related to bids received for Brayton Point and Kincaid and management’s decision to cease operations and begin decommissioning Kewaunee in 2013. Favorable drivers include the absence of an impairment charge related to certain utility coal-fired power stations and the absence of restoration costs associated with damage caused by Hurricane Irene recorded in 2011.

2011 VS. 2010

Net income attributable to Dominion decreased by 50%. Unfavorable drivers include the absence of a gain on the sale of Dominion’s Appalachian E&P operations, lower margins from merchant generation operations, and the impact of less favorable weather, including Hurricane Irene, on electric utility operations. Favorable drivers include the absence of charges related to a workforce reduction program and the absence of a loss on the sale of Peoples, and higher earnings from rate adjustment clauses.

Analysis of Consolidated Operations

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

Year Ended December 31,	2012			$ Change			2011			$ Change			2010
(millions)
Operating Revenue	$	13,093		$	(1,052	)	$	14,145		$	(782	)	$	14,927
Electric fuel and other energy-related purchases		3,748			(349	)		4,097			63			4,034
Purchased electric capacity		387			(67	)		454			1			453
Purchased gas		1,177			(587	)		1,764			(285	)		2,049
Net Revenue		7,781			(49	)		7,830			(561	)		8,391
Other operations and maintenance		4,868			1,546			3,322			(126	)		3,448
Depreciation, depletion and amortization		1,186			120			1,066			31			1,035
Other taxes		571			23			548			24			524
Gain on sale of Appalachian E&P operations		—			—			—			(2,467	)		2,467
Other income		223			45			178			8			170
Interest and related charges		882			15			867			41			826
Income tax expense		146			(608	)		754			(1,358	)		2,112
Loss from discontinued operations		(22	)		3			(25	)		233			(258	)

An analysis of Dominion’s results of operations follows:

2012 VS. 2011

Net Revenue decreased 1%, primarily reflecting:

Ÿ A $161 million decrease from merchant generation operations, primarily reflecting a decrease in realized prices; and

Ÿ A $144 million decrease from regulated natural gas distribution operations primarily reflecting decreased rider revenue ($117 million) related to low income assistance programs.

These decreases were partially offset by:

Ÿ A $184 million increase from electric utility operations, primarily reflecting:

Ÿ The impact of rate adjustment clauses ($138 million);

Ÿ The absence of a charge recorded in 2011 based on the Biennial Review Order to refund revenues to customers ($81 million); and

Ÿ A decrease in net capacity expenses ($31 million); partially offset by

Ÿ The impact ($58 million) of a decrease in sales to retail customers, primarily due to a decrease in cooling and heating degree days ($184 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($126 million);

Ÿ A $57 million increase in retail energy marketing activities primarily due to price risk management activities; and

Ÿ A $6 million increase from regulated natural gas transmission operations, primarily due to new transportation assets placed in service.

35

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Other operations and maintenance increased 47%, primarily reflecting:

Ÿ A $1.6 billion impairment charge due to bids received for Brayton Point and Kincaid;

Ÿ A $415 million impairment charge due to management’s decision to cease operations and begin decommissioning Kewaunee in 2013; and

Ÿ A $107 million increase in salaries, wages and benefits.

These increases were partially offset by:

Ÿ The absence of an impairment charge recorded in 2011 related to certain utility coal-fired generating units ($228 million);

Ÿ A $117 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These expenses are recovered through rates and do not impact net income; and

Ÿ The absence of restoration costs recorded in 2011 associated with damages caused by Hurricane Irene ($96 million).

Depreciation, depletion and amortization increased 11%, primarily due to property additions.

Other Income increased 25%, primarily due to higher realized gains (including investment income) on nuclear decommissioning trust funds.

Income tax expense decreased 81%, primarily reflecting lower pre-tax income in 2012.

2011 VS. 2010

Net Revenue decreased 7%, primarily reflecting:

Ÿ A $504 million decrease from merchant generation operations, primarily due to a decrease in realized prices ($340 million) and lower generation ($153 million); and

Ÿ 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:

Ÿ A $32 million increase from Dominion’s gas transmission business primarily related to an increase in revenue from NGLs;

Ÿ A $28 million increase in producer services primarily related to higher physical margins and favorable price changes on economic hedging positions, all associated with natural gas aggregation, marketing and trading activities;

Ÿ A $13 million increase from electric utility operations, primarily reflecting:

Ÿ The impact of rate adjustment clauses ($169 million); and

Ÿ A decrease in net capacity expenses ($44 million); partially offset by

Ÿ The impact ($120 million) of a decrease in sales to retail customers, primarily due to a decrease in heating and cooling degree days ($220 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($100 million); and

Ÿ A decrease due to a charge based on the Biennial Review Order to refund revenues to customers ($81 million).

Other operations and maintenance decreased 4% primarily reflecting:

Ÿ A $434 million decrease in salaries, wages and benefits primarily related to a 2010 workforce reduction program; partially offset by

Ÿ A $228 million impairment charge related to certain utility coal-fired generating units; and

Ÿ A $96 million increase due to restoration costs associated with damage caused by Hurricane Irene.

Gain on sale of Appalachian E&P operations reflects a gain on the sale of these operations, as described in Note 3 to the Consolidated Financial Statements.

Interest and related charges increased 5%, primarily due to the absence of a benefit recorded in 2010 resulting from the discontinuance of hedge accounting for certain interest rate derivatives ($73 million) and an increase in debt issuances in 2011 ($18 million), partially offset by the recognition of hedging gains that had previously been deferred as regulatory liabilities as a result of the Biennial Review Order ($50 million).

Income tax expense decreased 64%, 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 2010, as well as losses associated with State Line and Salem Harbor, which were reclassified to discontinued operations as a result of their sale in 2012.

Outlook

Dominion’s strategy is to continue focusing on its regulated businesses while maintaining upside potential in well-positioned nonregulated businesses. The goals of this strategy are to provide earnings per share growth, a growing dividend and to maintain a stable credit profile. Dominion is in the process of transitioning to a more regulated earnings mix, and is targeting 80-90 percent of its earnings to come from regulated businesses in 2013 and beyond. This is evidenced by Dominion’s capital investments in regulated infrastructure, as well as its disposition of certain merchant generation facilities during 2012 and its announcement that certain other merchant generation facilities are expected to be sold or decommissioned in 2013.

In 2013, Dominion is expected to experience an increase in net income on a per share basis as compared to 2012. Dominion’s anticipated 2013 results reflect the following significant factors:

Ÿ The absence of impairment charges incurred in 2012 associated with certain merchant generating facilities;

Ÿ A return to normal weather in its electric utility operations;

Ÿ Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue, as well as full-year earnings from gas transmission and gas distribution projects placed in service in 2012; and

Ÿ Growth in weather-normalized electric utility sales of approximately 2% resulting from the recovering economy and rising energy demand; partially offset by

Ÿ An increase in interest expense;

Ÿ Increases in certain operations and maintenance expense; and

Ÿ An increase in depreciation, depletion and amortization.

On January 2, 2013, U.S. federal legislation was enacted that provides an extension of the 50 percent bonus depreciation allowance for qualifying capital expenditures incurred through 2013, as discussed in Note 5 to the Consolidated Financial Statements. Dominion expects the bonus depreciation provisions to reduce income taxes otherwise payable, resulting in cash savings in 2013 and 2014 of approximately $250 million and $350 million, respectively.

36

SEGMENT RESULTS OF OPERATIONS

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

Year Ended December 31,	2012						2011						2010
	Net Income attributable to Dominion			Diluted EPS			Net Income attributable to Dominion			Diluted EPS			Net Income attributable to Dominion		Diluted EPS
(millions, except EPS)
DVP	$	559		$	0.98		$	501		$	0.87		$	448	$	0.76
Dominion Generation		874			1.52			968			1.68			1,263		2.14
Dominion Energy		551			0.96			521			0.91			475		0.80
Primary operating segments		1,984			3.46			1,990			3.46			2,186		3.70
Corporate and Other		(1,682	)		(2.93	)		(582	)		(1.01	)		622		1.06
Consolidated	$	302		$	0.53		$	1,408		$	2.45		$	2,808	$	4.76

DVP

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

Year Ended December 31,	2012		% Change			2011		% Change			2010
Electricity delivered (million MWh)		80.8		(2	)%		82.3		(3	)%		84.5
Degree days:
Cooling		1,787		(6	)		1,899		(9	)		2,090
Heating		2,955		(12	)		3,354		(12	)		3,819
Average electric distribution customer accounts (thousands)(1)		2,455		1			2,438		1			2,422
Average retail energy marketing customer accounts (thousands)(1)		2,129		(1	)		2,152		6			2,037

(1) Thirteen-month average.

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

2012 VS. 2011

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(34	)	$	(0.06	)
Other		28			0.05
FERC transmission equity return		19			0.04
Retail energy marketing operations		35			0.06
Storm damage and service restoration(1)		14			0.03
Other		(4	)		(0.01	)
Change in net income contribution	$	58		$	0.11

(1) Excludes restoration costs associated with damage caused by severe storms in 2012 and 2011, which are reflected in the Corporate and Other segment.

2011 VS. 2010

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(43	)	$	(0.07	)
Other		10			0.02
FERC transmission equity return		44			0.07
Retail energy marketing operations		6			0.01
Storm damage and service restoration(1)		9			0.02
Other operations and maintenance expense(2)		28			0.04
Other		(1	)		—
Share accretion		—			0.02
Change in net income contribution	$	53		$	0.11

(1) Excludes restoration costs associated with damage caused by Hurricane Irene which are reflected in the Corporate and Other segment.

(2) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.

Dominion Generation

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

Year Ended December 31,	2012		% Change			2011		% Change			2010
Electricity supplied (million MWh):
Utility		80.8		(2	)%		82.3		(3	)%		84.5
Merchant(1)		41.4		(4	)		43.0		(9	)		47.3
Degree days (electric utility service area):
Cooling		1,787		(6	)		1,899		(9	)		2,090
Heating		2,955		(12	)		3,354		(12	)		3,819

(1) Includes 13.2, 17.3, and 22.7 million MWh for the years ended December 31, 2012, 2011, and 2010, respectively, related to Kewaunee, State Line, Salem Harbor, Brayton Point, Kincaid, and Dominion’s 50% interest in Elwood.

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

2012 VS. 2011

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Merchant generation margin	$	(109	)	$	(0.19	)
Regulated electric sales:
Weather		(78	)		(0.14	)
Other		46			0.08
Brayton Point, Kincaid and Elwood third and fourth quarter 2011 earnings(1)		7			0.01
Rate adjustment clause equity return		17			0.03
PJM ancillary services		(27	)		(0.05	)
Net capacity expenses		19			0.04
Outage costs		8			0.01
Other		23			0.05
Change in net income contribution	$	(94	)	$	(0.16	)

(1) Brayton Point’s, Kincaid’s and Elwood’s third and fourth quarter 2012 results of operations have been reflected in the Corporate and Other segment due to Dominion’s decision, in the third quarter of 2012, to pursue the sale of Brayton Point, Kincaid, and its 50% interest in Elwood.

37

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

2011 VS. 2010

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Merchant generation margin	$	(278	)	$	(0.48	)
Regulated electric sales:
Weather		(91	)		(0.16	)
Other		59			0.10
Rate adjustment clause equity return		30			0.05
Outage costs		(11	)		(0.01	)
Other operations and maintenance expenses(1)		72			0.13
Depreciation and amortization		(7	)		(0.01	)
Interest expense		(18	)		(0.03	)
Kewaunee 2010 earnings(2)		(19	)		(0.03	)
Other		(32	)		(0.06	)
Share accretion		—			0.04
Change in net income contribution	$	(295	)	$	(0.46	)

(1) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.

(2) 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. In 2012, Dominion decided to cease operations and begin decommissioning the facility in 2013.

Dominion Energy

Presented below are selected operating statistics related to Dominion Energy’s operations. As discussed in Note 3, in April 2010 Dominion completed the sale of substantially all of its Appalachian E&P operations. As a result, production-related operating statistics for the Dominion Energy segment are no longer significant.

Year Ended December 31,	2012		% Change			2011		% Change			2010
Gas distribution throughput (bcf):
Sales		26		(13	)%		30		(3	)%		31
Transportation		259		2			253		5			241
Heating degree days		4,986		(11	)		5,584		(2	)		5,682
Average gas distribution customer accounts (thousands)(1):
Sales		251		(2	)		256		(2	)		260
Transportation		1,044		—			1,040		—			1,042

(1) Thirteen-month average.

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

2012 VS. 2011

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Weather	$	(5	)	$	(0.01	)
Producer services margin		(13	)		(0.02	)
Gas transmission margin(1)		8			0.01
Gain from sale of assets to Blue Racer		43			0.08
Other		(3	)		(0.01	)
Change in net income contribution	$	30		$	0.05

(1) Primarily reflects placing the Appalachian Gateway Project into service.

2011 VS. 2010

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Producer services margin	$	18		$	0.03
Gas transmission margin(1)		15			0.03
Other operations and maintenance expenses(2)		11			0.02
Gas distribution margin:
AMR and PIR revenue		9			0.02
Base gas sales		(4	)		(0.01	)
E&P disposed operations		(17	)		(0.03	)
Other		14			0.02
Share accretion		—			0.03
Change in net income contribution	$	46		$	0.11

(1) Primarily reflects an increase in revenue from NGLs.

(2) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.

Corporate and Other

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

Year Ended December 31,	2012			2011			2010
(millions, except EPS amounts)
Specific items attributable to operating segments	$	(1,442	)	$	(340	)	$	1,042
Specific items attributable to Corporate and Other segment:
Peoples discontinued operations		—			—			(155	)
Other		(5	)		29			(22	)
Total specific items		(1,447	)		(311	)		865
Other corporate operations		(235	)		(271	)		(243	)
Total net benefit (expense)	$	(1,682	)	$	(582	)	$	622
EPS impact	$	(2.93	)	$	(1.01	)	$	1.06

TOTAL SPECIFIC ITEMS

Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 25 to the Consolidated Financial Statements for discussion of these items.

VIRGINIA POWER

RESULTS OF OPERATIONS

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

Year Ended December 31,	2012		$ Change		2011		$ Change			2010
(millions)
Net Income	$	1,050	$	228	$	822	$	(30	)	$	852

Overview

2012 VS. 2011

Net income increased by 28%. Favorable drivers include the absence of an impairment charge related to certain coal-fired

38

power stations recorded in 2011, the impact of rate adjustment clauses, and the absence of restoration costs associated with damage caused by Hurricane Irene recorded in 2011. Unfavorable drivers include the impact of less favorable weather and the restoration costs associated with damage caused by severe storms.

2011 VS. 2010

Net income decreased by 4%, primarily reflecting less favorable weather, including Hurricane Irene, and an impairment charge related to certain coal-fired power stations, partially offset by higher earnings from rate adjustment clauses and the absence of charges related to a workforce reduction program.

Analysis of Consolidated Operations

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

Year Ended December 31,	2012		$ Change			2011		$ Change			2010
(millions)
Operating Revenue	$	7,226	$	(20	)	$	7,246	$	27		$	7,219
Electric fuel and other energy-related purchases		2,368		(138	)		2,506		11			2,495
Purchased electric capacity		386		(66	)		452		3			449
Net Revenue		4,472		184			4,288		13			4,275
Other operations and maintenance		1,466		(277	)		1,743		(2	)		1,745
Depreciation and amortization		782		64			718		47			671
Other taxes		232		10			222		4			218
Other income		96		8			88		(12	)		100
Interest and related charges		385		54			331		(16	)		347
Income tax expense		653		113			540		(2	)		542

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

2012 VS. 2011

Net Revenue increased 4%, primarily reflecting:

Ÿ The impact of rate adjustment clauses ($138 million);

Ÿ The absence of a charge recorded in 2011 based on the Biennial Review Order to refund revenues to customers ($81 million); and

Ÿ A decrease in net capacity expenses ($31 million); partially offset by

Ÿ The impact ($58 million) of a decrease in sales to retail customers, primarily due to a decrease in cooling and heating degree days ($184 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($126 million).

Other operations and maintenance decreased 16%, primarily reflecting:

Ÿ The absence of an impairment charge recorded in 2011 related to certain coal-fired generating units ($228 million); and

Ÿ The absence of restoration costs recorded in 2011 associated with damage caused by Hurricane Irene ($96 million); partially offset by

Ÿ A $64 million increase in storm damage and service restoration costs primarily due to the damage caused by severe storms in 2012.

Interest and related charges increased 16%, primarily due to the absence of the recognition of hedging gains into income in 2011, that had been deferred as regulatory liabilities, as a result of the Biennial Review Order.

Income tax expense increased 21%, primarily reflecting higher pre-tax income in 2012.

2011 VS. 2010

Net Revenue increased $13 million, primarily reflecting:

Ÿ The impact of rate adjustment clauses ($169 million); and

Ÿ A decrease in net capacity expenses ($44 million); partially offset by

Ÿ The impact ($120 million) of a decrease in sales to retail customers, primarily due to a decrease in heating and cooling degree days ($220 million), partially offset by an increase in sales due to the effect of favorable economic conditions on customer usage and other factors ($100 million); and

Ÿ A decrease due to a charge based on the Biennial Review Order to refund revenues to customers ($81 million).

Other operations and maintenance decreased $2 million, primarily reflecting:

Ÿ A $267 million decrease in salaries, wages and benefits as well as certain administrative and general costs primarily due to a 2010 workforce reduction program; and

Ÿ A $54 million decrease in planned outage costs primarily due to fewer scheduled outage days at certain generation facilities; partially offset by

Ÿ A $228 million impairment charge related to certain coal-fired generating units; and

Ÿ A $96 million increase due to restoration costs associated with damage caused by Hurricane Irene.

Other income decreased 12%, primarily due to a decrease in the equity component of AFUDC ($17 million), partially offset by an increase in amounts collectible from customers for taxes in connection with contributions in aid of construction ($5 million).

Outlook

Virginia Power expects to provide growth in net income in 2013. Virginia Power’s anticipated 2013 results reflect the following significant factors:

Ÿ A return to normal weather;

Ÿ Growth in weather-normalized electric sales of approximately 2% resulting from the recovering economy and rising energy demand; and

Ÿ Construction and operation of growth projects and associated rate adjustment clause revenue; partially offset by

Ÿ Increases in certain operations and maintenance expense; and

Ÿ An increase in depreciation, depletion and amortization.

On January 2, 2013, U.S. federal legislation was enacted that provides an extension of the 50 percent bonus depreciation allowance for qualifying capital expenditures incurred through

2013, as discussed in Note 5 to the Consolidated Financial

39

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Statements. Virginia Power expects the bonus depreciation provisions to reduce income taxes otherwise payable, resulting in cash savings in 2013 and 2014 of approximately $200 million and $250 million, respectively.

SEGMENT RESULTS OF OPERATIONS

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

Year Ended December 31,	2012			$ Change			2011			$ Change			2010
(millions)
DVP	$	448		$	22		$	426		$	49		$	377
Dominion Generation		653			(11	)		664			34			630
Primary operating segments		1,101			11			1,090			83			1,007
Corporate and Other		(51	)		217			(268	)		(113	)		(155	)
Consolidated	$	1,050		$	228		$	822		$	(30	)	$	852

DVP

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

Year Ended December 31,	2012		% Change			2011		% Change			2010
Electricity delivered (million MWh)		80.8		(2	)%		82.3		(3	)%		84.5
Degree days (electric service area):
Cooling		1,787		(6	)		1,899		(9	)		2,090
Heating		2,955		(12	)		3,354		(12	)		3,819
Average electric distribution customer accounts (thousands)(1)		2,455		1			2,438		1			2,422

(1) Thirteen-month average.

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

2012 VS. 2011

	Increase (Decrease)
(millions, except EPS)
Regulated electric sales:
Weather	$	(34	)
Other		28
FERC transmission equity return		19
Storm damage and service restoration(1)		14
Other		(5	)
Change in net income contribution	$	22

(1) Excludes restoration costs associated with damage caused by severe storms in 2012 and 2011, which are reflected in the Corporate and Other segment.

2011 VS. 2010

	Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	(43	)
Other		10
FERC transmission equity return		44
Storm damage and service restoration(1)		9
Other operations and maintenance expense(2)		28
Other		1
Change in net income contribution	$	49

(1) Excludes restoration costs associated with damage caused by Hurricane Irene which are reflected in the Corporate and Other segment.

(2) Primarily reflects the 2010 implementation of cost containment measures including a workforce reduction program, and lower salaries and wages expenses.

Dominion Generation

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

Year Ended December 31,	2012		% Change			2011		% Change			2010
Electricity supplied (million MWh)		80.8		(2	)%		82.3		(3	)%		84.5
Degree days (electric service area):
Cooling		1,787		(6	)		1,899		(9	)		2,090
Heating		2,955		(12	)		3,354		(12	)		3,819

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

2012 VS. 2011

	Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	(78	)
Other		46
Rate adjustment clause equity return		17
PJM ancillary services		(27	)
Net capacity expenses		19
Other		12
Change in net income contribution	$	(11	)

2011 VS. 2010

	Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	(91	)
Other		59
Rate adjustment clause equity return		30
Outage costs		33
Other		3
Change in net income contribution	$	34

40

Corporate and Other

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

Year Ended December 31,	2012			2011			2010
(millions)
Specific items attributable to operating segments	$	(51	)	$	(268	)	$	(153	)
Other corporate operations		—			—			(2	)
Total net expense	$	(51	)	$	(268	)	$	(155	)

SPECIFIC ITEMS ATTRIBUTABLE TO OPERATING SEGMENTS

Corporate and Other primarily includes specific items attributable to Virginia Power’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 25 to the Consolidated Financial Statements for a discussion of these items.

SELECTED INFORMATION—ENERGY TRADING ACTIVITIES

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

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

	Amount
(millions)
Net unrealized gain at December 31, 2011	$	20
Contracts realized or otherwise settled during the period		3
Change in unrealized gains and losses		55
Net unrealized gain at December 31, 2012	$	78

The balance of net unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes at December 31, 2012, is summarized in the following table based on the approach used to determine fair value:

	Maturity Based on Contract Settlement or Delivery Date(s)
Sources of Fair Value	2013		2014—2015			2016—2017			2018 and thereafter		Total
(millions)
Prices actively quoted—Level 1(1)	$	—	$	—		$	—		$	—	$	—
Prices provided by other external sources—Level 2(2)		59		26			2			—		87
Prices based on models and other valuation methods—Level 3(3)		1		(6	)		(4	)		—		(9	)
Total	$	60	$	20		$	(2	)	$	—	$	78

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

At December 31, 2012, Dominion had $1.1 billion of unused capacity under its credit facilities, including $256 million of unused capacity under joint credit facilities available to Virginia Power. See additional discussion under Credit Facilities and Short-Term Debt.

The disposition of certain merchant generation facilities during 2012 and the expected sale or decommissioning of certain other merchant generation facilities in 2013 are not expected to negatively impact Dominion’s liquidity.

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

Year Ended December 31,	2012			2011			2010
(millions)
Cash and cash equivalents at beginning of year	$	102		$	62		$	50
Cash flows provided by (used in):
Operating activities		4,137			2,983			1,825
Investing activities		(3,840	)		(3,321	)		419
Financing activities		(151	)		378			(2,232	)
Net increase in cash and cash equivalents		146			40			12
Cash and cash equivalents at end of year	$	248		$	102		$	62

41

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

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

Year Ended December 31,	2012			2011			2010
(millions)
Cash and cash equivalents at beginning of year	$	29		$	5		$	19
Cash flows provided by (used in):
Operating activities		2,706			2,024			1,409
Investing activities		(2,282	)		(1,947	)		(2,425	)
Financing activities		(425	)		(53	)		1,002
Net increase (decrease) in cash and cash equivalents		(1	)		24			(14	)
Cash and cash equivalents at end of year	$	28		$	29		$	5

Operating Cash Flows

In 2012, net cash provided by Dominion’s operating activities increased by approximately $1.2 billion, primarily due to higher deferred fuel cost recoveries in its Virginia jurisdiction, lower margin collateral requirements, changes in other working capital items and income tax refunds in 2012 as compared to income tax payments in 2011. The increase was partially offset by lower merchant generation margins and the impact of less favorable weather.

In 2012, net cash provided by Virginia Power’s operating activities increased by $682 million, primarily due to higher deferred fuel cost recoveries in its Virginia jurisdiction and net changes in other working capital items, partially offset by income tax payments in 2012 as compared to income tax refunds in 2011 and the impact of less favorable weather.

Dominion believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In 2012, Dominion’s Board of Directors adopted a new dividend policy that raised its target payout ratio to 65-70%, and established an annual dividend rate for 2013 of $2.25 per share of common stock, a 6.6% increase over the 2012 rate. Declarations of dividends are subject to further Board of Directors approval. 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, and which are discussed in Item 1A. Risk Factors.

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 December 31, 2012 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade(1)	$	281	$	—	$	281
Non-investment grade(2)		4		—		4
No external ratings:
Internally rated-investment grade(3)		113		—		113
Internally rated-non-investment grade(4)		114		—		114
Total	$	512	$	—	$	512

(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 28% 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 13% of the total net credit exposure.

(4) The five largest counterparty exposures, combined, for this category represented approximately 15% of the total net credit exposure.

Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers and was not considered material at December 31, 2012.

Investing Cash Flows

In 2012, net cash used in Dominion’s investing activities increased by $519 million, primarily due to higher capital expenditures, mainly related to investments in growth projects, and lower restricted cash reimbursements for the purpose of funding certain qualifying construction projects, partially offset by proceeds from the sale of assets, primarily related to Blue Racer, in 2012.

In 2012, net cash used in Virginia Power’s investing activities increased by $335 million, primarily due to higher capital expenditures and lower restricted cash reimbursements for the purpose of funding certain qualifying construction projects.

Financing Cash Flows and Liquidity

Dominion and Virginia Power rely on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by their operations. As discussed in Credit Ratings, 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 for certain issuances and, in the case of Virginia Power, approval by the Virginia Commission.

Each of the Companies currently 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. 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 registra-

42

tion statements to register any offering of securities, other than those for exchange offers or business combination transactions.

In 2012, net cash used in Dominion’s financing activities was $151 million as compared to net cash provided by financing activities of $378 million in 2011, primarily reflecting lower net debt issuances in 2012 as compared to 2011 as a result of higher cash flow from operations, partially offset by the absence of the repurchases of common stock recorded in 2011.

In 2012, net cash used in Virginia Power’s financing activities increased by $372 million, primarily reflecting lower net debt issuances in 2012 as compared to 2011 as a result of higher cash flow from operations.

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.

In connection with commodity hedging activities, the Companies are required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, the Companies may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, the Companies vary the form of collateral provided to counterparties after weighing the costs and benefits of various factors associated with the different forms of collateral. These factors include short-term borrowing and short-term investment rates, the spread over these short-term rates at which the Companies can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives.

Dominion

Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:

December 31, 2012	Facility Limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility(1)	$	3,000	$	2,412		$	—	$	588
Joint revolving credit facility(2)		500		—			26		474
Total	$	3,500	$	2,412	(3)	$	26	$	1,062

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

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

(3) The weighted-average interest rate of the outstanding commercial paper supported by Dominion’s credit facilities was 0.49% at December 31, 2012.

Virginia Power

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.

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:

December 31, 2012	Facility Sub-limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Sub-limit Capacity Available
(millions)
Joint revolving credit facility(1)	$	1,000	$	992		$	—	$	8
Joint revolving credit facility(2)		250		—			2		248
Total	$	1,250	$	992	(3)	$	2	$	256

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

(2) Effective September 2012, the maturity date for $400 million of the $500 million in committed capacity of this credit facility was extended from September 2016 to September 2017. The remaining $100 million continues to have a maturity date of September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.

(3) The weighted-average interest rate of the outstanding commercial paper supported by these credit facilities was 0.47% at December 31, 2012.

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

SHORT-TERM NOTES

In November and December 2012, Dominion issued $250 million and $150 million, respectively, of private placement short-term notes that mature in November 2013 and bear interest at a variable rate. The proceeds were used for general corporate purposes.

LONG-TERM DEBT

During 2012, Dominion and Virginia Power issued the following long-term debt:

Type	Principal		Rate			Maturity		Issuing Company
	(millions)
Senior notes	$	350		1.40	%		2017		Dominion
Senior notes		350		2.75	%		2022		Dominion
Senior notes		350		4.05	%		2042		Dominion
Senior notes		450		2.95	%		2022		Virginia Power
Total notes issued	$	1,500

In December 2011, Virginia Power borrowed $75 million in connection with the Economic Development Authority of the County of Chesterfield Pollution Control Refunding Revenue

43

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Bonds, Series 2011 A, which mature in 2017 and bear interest during the initial period 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, using a remarketing process. The proceeds were used to refund the principal amount of the Industrial Development Authority of the County of Chesterfield, Virginia Money Market Municipals^TM Pollution Control Revenue Bonds, Series 1987 A and Series 1987 B that would otherwise have matured in June 2017.

During 2012, Dominion and Virginia Power repaid and repurchased $1.7 billion and $641 million, respectively, of long-term debt.

ISSUANCE OF COMMON STOCK

Dominion maintains Dominion Direct^® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2012, Dominion began issuing new common shares for these direct stock purchase plans.

During 2012, Dominion issued approximately 6.4 million shares of common stock through various programs. Dominion received cash proceeds of $265 million from the issuance of 5.3 million of such shares through Dominion Direct, employee savings plans, and the exercise of employee stock options.

In January 2012, Dominion filed a new SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at the market program. Dominion entered into four separate Sales Agency Agreements to effect sales under the program. However, with the exception of issuing approximately $318 million in equity through employee savings plans, direct stock purchase and dividend reinvestment plans, converted securities and other employee and director benefit plans, Dominion did not issue common stock in 2012.

In 2012, Virginia Power did not issue any shares of its common stock to Dominion.

REPURCHASE OF COMMON STOCK

Dominion did not repurchase any shares in 2012 and does not plan to repurchase shares during 2013, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization.

BORROWINGS FROM PARENT

Virginia Power has the ability to borrow funds from Dominion under both short-term and long-term borrowing arrangements. Virginia Power’s short-term demand note borrowings from Dominion were $243 million at December 31, 2012. There were no long-term borrowings from Dominion at December 31, 2012. At December 31, 2012, Virginia Power’s nonregulated subsidiaries had outstanding borrowings, net of repayments, under the Dominion money pool of $192 million.

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. Dominion and Virginia Power believe that their current

credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion and Virginia Power may affect their ability to access these funding sources or cause an increase in the return required by investors. Dominion’s and Virginia Power’s credit ratings may affect their liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which they are able to offer their debt securities.

Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for Dominion and Virginia Power are affected by each company’s financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.

Credit ratings as of February 22, 2013 follow:

	Fitch		Moody’s		Standard & Poor’s
Dominion
Senior unsecured debt securities		BBB+		Baa2		A-
Junior subordinated debt securities		BBB-		Baa3		BBB
Enhanced junior subordinated notes		BBB-		Baa3		BBB
Commercial paper		F2		P-2		A-2
Virginia Power
Mortgage bonds		A		A1		A
Senior unsecured (including tax-exempt) debt securities		A-		A3		A-
Junior subordinated debt securities		BBB		Baa1		BBB
Preferred stock		BBB		Baa2		BBB
Commercial paper		F2		P-2		A-2

As of February 22, 2013, Fitch, Moody’s and Standard & Poor’s maintained a stable outlook for their respective ratings of Dominion and Virginia Power.

A downgrade in an individual company’s credit rating would not necessarily restrict its ability to raise short-term and long-term financing as long as its credit rating remains investment grade, but it would likely increase the cost of borrowing. Dominion and Virginia Power work closely with Fitch, Moody’s and Standard & Poor’s with the objective of maintaining their current credit ratings. The Companies may find it necessary to modify their business plans to maintain or achieve appropriate credit ratings and such changes may adversely affect growth and EPS.

Debt Covenants

As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion and Virginia Power must enter into enabling agreements. These agreements contain covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with

44

each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion and Virginia Power.

Some of the typical covenants include:

Ÿ The timely payment of principal and interest;

Ÿ Information requirements, including submitting financial reports filed with the SEC and information about changes in Dominion’s and Virginia Power’s credit ratings to lenders;

Ÿ Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation, and restrictions on disposition of all or substantially all assets;

Ÿ Compliance with collateral minimums or requirements related to mortgage bonds; and

Ÿ Limitations on liens.

Dominion and Virginia Power are required to pay annual commitment fees to maintain their credit facilities. In addition, their credit agreements contain various terms and conditions that could affect their ability to borrow under these facilities. They include maximum debt to total capital ratios and cross-default provisions.

As of December 31, 2012, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:

Company	Maximum Allowed Ratio			Actual  Ratio(1)
Dominion		65	%		60	%
Virginia Power		65	%		46	%

(1) Indebtedness as defined by the bank agreements excludes junior subordinated notes reflected as long-term debt or securities due within one year as well as AOCI reflected as equity in the Consolidated Balance Sheets.

These provisions apply separately to Dominion and Virginia Power.

If Dominion or Virginia Power or any of either company’s material subsidiaries fails to make payment on various debt obligations in excess of $100 million, the lenders could require that company to accelerate its repayment of any outstanding borrowings under the credit facility and the lenders could terminate their commitment to lend funds to that company. Accordingly, any default by Dominion will not affect the lenders’ commitment to Virginia Power. However, any default by Virginia Power would affect the lenders’ commitment to Dominion under the joint credit agreements.

Dominion executed RCCs in connection with its issuance of the following hybrid securities:

Ÿ June 2006 hybrids;

Ÿ September 2006 hybrids; and

Ÿ June 2009 hybrids.

See Note 17 to the Consolidated Financial Statements for terms of the RCCs.

At December 31, 2012, the termination dates and covered debt under the RCCs associated with Dominion’s hybrids were as follows:

Hybrid	RCC Termination Date			Designated Covered Debt Under RCC
June 2006 hybrids		6/30/2036			September 2006 hybrids
September 2006 hybrids		9/30/2036			June 2006 hybrids
June 2009 hybrids		6/15/2034	(1)		2008 Series B Senior Notes, 7.0% due 2038

(1) Automatically extended, as set forth in the RCC, for additional quarterly periods, to the extent the maturity date is extended.

Dominion and Virginia Power monitor the debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2012, there have been no events of default under or changes to Dominion’s or Virginia Power’s debt covenants.

Virginia Power Mortgage Supplement

Substantially all of Virginia Power’s property is subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. In July 2012, Virginia Power entered into a supplement to the indenture in order to amend various of its terms and conditions and to incorporate certain new provisions. The supplement reduces Virginia Power’s overall compliance responsibilities associated with the indenture by limiting the maximum principal amount of bonds that may be outstanding under the indenture to $10 million unless otherwise provided in a further supplement, and by modifying or eliminating altogether certain compliance requirements while there are no bonds outstanding. The supplement also provides Virginia Power with flexibility to determine when or if certain newly or recently acquired properties will be pledged as collateral under the indenture. There were no bonds outstanding as of December 31, 2012; however, by leaving the indenture open, Virginia Power expects to retain the flexibility to issue mortgage bonds in the future.

Dividend Restrictions

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2012, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

Certain agreements associated with Dominion’s and Virginia Power’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion or Virginia Power’s ability to pay dividends or receive dividends from their subsidiaries at December 31, 2012.

See Note 17 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes, which information is incorporated herein by reference.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

CONTRACTUAL OBLIGATIONS

Dominion and Virginia Power are party to numerous contracts and arrangements obligating them to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion and Virginia Power are parties as of December 31, 2012. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts

45

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

presented below. The table excludes all amounts classified as current liabilities in the Consolidated Balance Sheets, other than current maturities of long-term debt, interest payable and certain derivative instruments. The majority of Dominion’s and Virginia Power’s current liabilities will be paid in cash in 2013.

Dominion	2013		2014- 2015		2016- 2017		2018 and thereafter		Total
(millions)
Long-term debt(1)	$	2,200	$	2,058	$	2,790	$	11,940	$	18,988
Interest payments(2)		898		1,693		1,457		12,218		16,266
Leases(3)		79		136		118		161		494
Purchase obligations(4):
Purchased electric capacity for utility operations		350		695		456		327		1,828
Fuel commitments for utility operations		716		778		265		259		2,018
Fuel commitments for nonregulated operations		254		258		116		187		815
Pipeline transportation and storage		131		174		96		366		767
Energy commodity purchases for resale(5)		79		32		29		146		286
Other(6)		469		56		7		21		553
Other long-term liabilities(7):
Financial derivative-commodities(5)		48		29		3		—		80
Other contractual obligations(8)		16		12		30		2		60
Total cash payments	$	5,240	$	5,921	$	5,367	$	25,627	$	42,155

(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.

(2) Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2012 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 17 to the Consolidated Financial Statements. Does not reflect Dominion’s ability to defer interest payments on junior subordinated notes.

(3) Primarily consists of operating leases.

(4) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.

(5) Represents the summation of settlement amounts, by contracts, due from Dominion if all physical or financial transactions among its counterparties and Dominion were liquidated and terminated.

(6) Includes capital, operations, and maintenance commitments.

(7) Excludes regulatory liabilities, AROs and employee benefit plan obligations, which are not contractually fixed as to timing and amount. See Notes 12, 14 and 21 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $233 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 5 to the Consolidated Financial Statements.

(8) Includes interest rate swap agreements.

Virginia Power	2013		2014- 2015		2016- 2017		2018 and thereafter		Total
(millions)
Long-term debt(1)	$	418	$	228	$	1,155	$	4,875	$	6,676
Interest payments(2)		342		660		594		3,869		5,465
Leases(3)		26		43		26		26		121
Purchase obligations(4):
Purchased electric capacity for utility operations		350		695		456		327		1,828
Fuel commitments for utility operations		716		778		265		259		2,018
Transportation and storage		27		52		40		197		316
Other(5)		302		29		4		12		347
Total cash payments(6)	$	2,181	$	2,485	$	2,540	$	9,565	$	16,771

(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.

(2) Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2012 and outstanding principal for each instrument with the terms ending at each instrument’s stated maturity. See Note 17 to the Consolidated Financial Statements.

(3) Primarily consists of operating leases.

(4) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.

(5) Includes capital, operations, and maintenance commitments.

(6) Excludes regulatory liabilities, AROs and employee benefit plan contributions that are not contractually fixed as to timing and amount. See Notes 12, 14 and 21 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $57 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 5 to the Consolidated Financial Statements.

PLANNED CAPITAL EXPENDITURES

Dominion’s planned capital expenditures are expected to total approximately $4.7 billion, $4.2 billion and $3.3 billion in 2013, 2014 and 2015, respectively. Dominion’s expenditures are expected to include construction and expansion of electric generation and natural gas transmission and storage facilities, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel and the buyout of the lease at Fairless in 2013.

Virginia Power’s planned capital expenditures are expected to total approximately $2.6 billion, $3.0 billion and $2.3 billion in 2013, 2014 and 2015, respectively. Virginia Power’s expenditures are expected to include construction and expansion of electric generation facilities, construction improvements and expansion of electric transmission and distribution assets and purchases of nuclear fuel.

Dominion and Virginia Power expect to fund their capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the respective company’s Board of Directors.

Based on available generation capacity and current estimates of growth in customer demand, Virginia Power will need additional generation in the future. See DVP, Dominion Generation and Dominion Energy-Properties in Item 1. Business for a discussion of Dominion’s and Virginia Power’s expansion plans.

These estimates are based on a capital expenditures plan reviewed and endorsed by Dominion’s Board of Directors in late

46

2012 and are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. The Companies may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.

Use of Off-Balance Sheet Arrangements

GUARANTEES

Dominion primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others. See Note 22 to the Consolidated Financial Statements for additional information, which information is incorporated herein by reference.

FUTURE ISSUES AND OTHER MATTERS

See Item 1. Business, Item 3. Legal Proceedings, and Notes 13 and 22 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other matters that may impact future results of operations, financial condition, and/or cash flows.

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.

ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES

Dominion incurred approximately $189 million, $184 million and $228 million of expenses (including depreciation) during 2012, 2011, and 2010 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $193 million and $181 million in 2013 and 2014, respectively. In addition, capital expenditures related to environmental controls were $213 million, $403 million, and $351 million for 2012, 2011 and 2010, respectively. These expenditures are expected to be approximately $75 million and $115 million for 2013 and 2014, respectively.

Virginia Power incurred approximately $120 million, $129 million and $144 million of expenses (including depreciation) during 2012, 2011 and 2010, respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $148 million and $157 million in 2013 and 2014, respectively. In addition, capital expenditures related to environmental controls were $34 million, $77 million and $101 million for 2012, 2011 and 2010, respectively. These expenditures are expected to be approximately $20 million and $99 million for 2013 and 2014, respectively.

FUTURE ENVIRONMENTAL REGULATIONS

Air

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 December 2012, the EPA issued a final rule that set a more stringent annual air quality standard for fine particulate matter. The EPA is expected to complete final air quality designations by December 2014. States will have until 2020 to meet the revised standard. The extent to which a revised particulate matter standard will impact Dominion is uncertain at this time, but is not expected to be material.

The EPA has finalized rules establishing a new 1-hour NAAQS for NO₂ and a new 1-hour NAAQS for SO₂, which could require additional NO_X and SO₂ controls in certain areas where the Companies operate. Until the states have developed implementation plans for these standards, the impact on Dominion’s or Virginia Power’s facilities that emit NO_X and SO₂ is uncertain.

In January 2010, the EPA also proposed a new, more stringent NAAQS for ozone and had planned to finalize the rule in 2011. In September 2011, the EPA announced a delay from 2011 to 2014 of the rulemaking, therefore NO_x controls that may have been required by the rulemaking are also expected to be delayed. In the interim, the EPA is proceeding with implementation of the current ozone standard and made final attainment/nonattainment designations in May 2012. Several Dominion electric generating facilities are located in areas impacted by this standard. Until the states have developed implementation plans for the new NO_x, SO₂ and ozone standards, it is not possible to determine the impact on Dominion’s or Virginia Power’s facilities that emit NO_X and SO₂. The Companies cannot currently predict with certainty whether or to what extent the new rules will ultimately require additional controls, however, if significant expenditures are required, it could adversely affect Dominion’s results of operations, and Dominion’s and Virginia Power’s cash flows.

In June 2005, the EPA finalized amendments to the Regional Haze Rule, also known as the Clean Air Visibility Rule. The rule requires the states to implement Best Available Retrofit Technology requirements for sources to address impacts to visual air quality through regional haze state implementation plans, but allows other alternative options. The EPA is in the process of completing rulemakings on regional haze state implementation plans. Although Dominion and Virginia Power anticipate that the emission reductions achieved through compliance with other CAA-required programs will generally address this rule, additional emission reduction requirements may be imposed on the Companies’ facilities.

Water

The CWA is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. Dominion and Virginia Power must comply with all aspects of the CWA programs at their operating facilities. In July 2004, the EPA published regulations under CWA Section 316(b) that govern existing utilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold. In April 2008, the U.S. Supreme Court granted an industry

47

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

request to review the question of whether Section 316(b) authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. The U.S. Supreme Court ruled in April 2009 that the EPA has the authority to consider costs versus environmental benefits in selecting the best technology available for reducing impacts of cooling water intakes at power stations. It is currently unknown how the EPA will interpret the ruling in its ongoing rulemaking activity addressing cooling water intakes as well as how the states will implement this decision. In April 2011, the EPA published the proposed rule related to Section 316(b) in the Federal Register, and agreed to publish a final rule no later than July 27, 2012. In July 2012, the EPA announced a delay to no later than June 27, 2013 of its impending rulemaking related to Section 316(b).

The rule in its proposed form seeks to establish a uniform national standard for impingement, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA proposes to delegate entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of nine facility-specific factors, including a social cost-benefit test.

The proposed rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Under this proposal, Dominion has 16 facilities that may be subject to these proposed regulations. If finalized as proposed, Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power cannot estimate the need or potential for entrainment controls under the proposed rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. However, the impacts of this proposed rule may be material to the results of operations, financial condition and/or cash flows.

Solid and Hazardous Waste

In June 2010, the EPA proposed federal regulations under the RCRA for management of coal combustion by-products generated by power plants. The EPA is considering two possible options for the regulation of coal combustion by-products, both of which fall under the RCRA. Under the first proposal, the EPA would classify these by-products as special wastes subject to regulation under subtitle C, the hazardous waste provisions of the RCRA, when destined for disposal at landfills or surface impoundments. Under the second proposal, the EPA would regulate coal combustion by-products under subtitle D of the RCRA, the section for non-hazardous wastes. While the Companies cannot currently predict the outcome of this matter, regulation under either option will affect Dominion’s and Virginia Power’s onsite disposal facilities and coal combustion by-product management practices, and potentially require material investments.

Climate Change Legislation and Regulation

In December 2009, the EPA issued their Final Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act, finding that GHGs “endanger

both the public health and the public welfare of current and future generations.” On April 1, 2010, the EPA and the Department of Transportation’s National Highway Safety Administration announced a joint final rule establishing a program that will dramatically reduce GHG emissions and improve fuel economy for new cars and trucks sold in the United States. These rules took effect in January 2011 and established GHG emissions as regulated pollutants under the CAA.

In May 2010, the EPA issued the Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule that, combined with prior actions, require Dominion and Virginia Power to obtain permits for GHG emissions for new and modified facilities over certain size thresholds, and meet best available control technology for GHG emissions. The EPA has issued draft guidance for GHG permitting, including best available control technology.

In April 2012, the EPA published proposed NSPS for GHG emissions for new electric generating units. This proposed rule sets national emission standards for new coal, oil, integrated gasification combined cycle, and combined cycle units larger than 25MW. The rule, which is expected to be finalized in the Spring of 2013, covers CO₂ only and does not apply to existing sources. New natural gas combined cycle units, including Brunswick County, are expected to be able to meet this standard. The rule also does not apply to any new or existing simple cycle combustion turbine units or biomass units. The schedule for a final rulemaking governing a GHG NSPS for existing sources is uncertain.

There are other legislative proposals that may be considered that would have an indirect impact on GHG emissions. There is the potential for the U.S. Congress to consider a mandatory Clean Energy Standard. In addition to possible federal action, some regions and states in which Dominion and Virginia Power operate have already adopted or may adopt GHG emission reduction programs. Any of these new or contemplated regulations may affect capital costs, or create significant permitting delays, for new or modified facilities that emit GHGs.

In July 2008, Massachusetts passed the GWSA. Among other provisions, the GWSA sets economy-wide GHG emissions reduction goals for Massachusetts, including reductions of 25% below 1990 levels by 2020, interim goals for 2030 and 2040 and reductions of 80% below 1990 levels by 2050. No regulations impacting Dominion under the GWSA have been proposed. Dominion operates Brayton Point in Massachusetts and acts as a retail electric supplier in Massachusetts, which are subject to the implementation of the GWSA.

In December 2009, the governors of 11 Northeast and mid-Atlantic states, including Connecticut, Maryland, Massachusetts, New York, Pennsylvania, and Rhode Island (RGGI states plus Pennsylvania) signed a memorandum of understanding committing their states toward developing a low carbon fuel standard to reduce GHG emissions from vehicles. The memorandum of understanding established a process to develop a regional framework by 2011 and examine the economic impacts of a low carbon fuel standard program. Although economic studies and policy options were examined in 2011, a definitive framework has yet to be established.

48

Dodd-Frank Act

The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The Dodd-Frank Act includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can choose to exempt their hedging transactions from these clearing and exchange trading requirements. Final rules for the over-the-counter derivative-related provisions of the Dodd-Frank Act will continue to be established through the ongoing rulemaking process of the applicable regulators. If, as a result of the rulemaking process, Dominion’s or Virginia Power’s derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs, including from higher margin requirements, for their derivative activities. In addition, implementation of, and compliance with, the over-the-counter derivative provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in increased costs related to the Companies’ derivative activities. Due to the ongoing rulemaking process, the Companies are currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on their financial condition, results of operations or cash flows.

Cove Point Export Project

Dominion is pursuing a liquefaction project at Cove Point, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. The project, which is expected to cost between approximately $3.4 billion and $3.8 billion, exclusive of financing costs, has a planned capacity of approximately 750 million cubic feet per day on the inlet and approximately 4.5 to 5 million metric tons per annum on the outlet. In 2011, Cove Point requested authorization from the DOE to export LNG to countries that have a free trade agreement requiring trade in natural gas with the U.S. as well as countries that do not have such a free trade agreement. In October 2011, Cove Point received authorization from the DOE to export LNG to free trade agreement countries and Cove Point expects to receive authorization from the DOE to export LNG to non-free trade agreement countries in 2013. In June 2012, FERC approved Cove Point’s request to initiate the pre-filing process under which environmental review for the project commenced. Approval of the project could take up to two years from the pre-filing approval date.

In March 2012, Cove Point entered into precedent agreements with two major companies, one of which is Sumitomo Corporation, pursuant to which Cove Point would provide liquefaction, storage and loading services but would not own or directly export the LNG. In October 2012, Cove Point and the unnamed company terminated their precedent agreement by mutual consent. In December 2012, Cove Point entered into a 20-year terminal services agreement with Pacific Summit Energy LLC, a U.S. subsidiary of Sumitomo Corporation, for half of the planned project capacity. The agreement contains final terms subject to certain conditions precedent which include conditions related to customer contracting. Cove Point is in active negotiations with a company for a definitive terminal services agreement for the remaining half of the planned project capacity.

In May 2012, in response to claims by the Sierra Club, Cove Point filed a complaint for declaratory judgment to confirm its right to construct the project. In January 2013, a Maryland circuit court issued declaratory judgment confirming Cove Point’s right to build liquefaction facilities. In February 2013, the Sierra Club filed a notice of appeal with the Maryland Court of Special Appeals.

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

Cove Point Re-Export Project

In August 2011, Cove Point filed an application with the DOE seeking blanket authority to re-export up to the equivalent of 150 bcf of foreign-sourced LNG from the Cove Point terminal over a two-year period. In January 2012, the DOE conditionally approved Cove Point’s application. Due to lack of customer interest in re-export, Cove Point made no filings with FERC and the DOE re-export authorization automatically terminated in January 2013.

Regulation Act Legislation

In January 2013, legislation was introduced in the Virginia General Assembly which would amend the Regulation Act. The legislation passed the Virginia House of Delegates and the Senate of Virginia and was signed into law by the governor in February 2013. Among other things the amendments eliminate the 50 basis points RPS ROE incentive prospectively, as well as the new generation ROE incentives for future projects, except for nuclear and offshore wind projects, which instead are reduced from the current 200 basis points ROE incentive to 100 basis points. ROE incentives for previously approved, as well as filed for but unconstructed projects, remain in place. In addition, the performance incentive provision of the Regulation Act, authorizing the Virginia Commission to increase or decrease a utility’s authorized ROE by up to 100 basis points based on operating comparisons with certain nationally recognized standards, is removed and the Virginia Commission has the discretion to increase or decrease a utility’s authorized ROE based on commission precedent that existed prior to the enactment of the Regulation Act. The legislation includes changes to the earnings test parameters defined by the Regulation Act to allow for a wider band of 70 basis points above and below the authorized ROE in determining whether a utility’s earned ROE is either insufficient or excessive beginning with the biennial review for 2013-2014 to be filed in 2015. Additionally, if a utility is deemed to have over-earned, the customer refund share of excess earnings increases to 70% from the current 60% level beginning with the biennial review for 2013-2014 to be filed in 2015. The legislation also provides guidance to the Virginia Commission on rate-making treatment for severe weather events and natural disasters and for asset impairments related to early retirements of utility generation plants, for which the decision to retire was made before December 31, 2012. This guidance on rate-making treatment applies to Virginia Power’s upcoming biennial review for 2011-2012 to be filed in 2013. Additionally, the provision in the Regulation Act requiring the Virginia Commission to combine transmission-related rider costs with base rates is eliminated and the transmission costs will con-

49

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

tinue to be segregated and recovered separately. The legislation requires a utility seeking approval to construct a generating facility to demonstrate that it has considered and weighed alternative options in its selection process.

Virginia Offshore Wind Lease

In March 2012, Virginia Power filed a notice with BOEM of its interest in obtaining leases off the Virginia coast in an area sufficient for construction of offshore wind turbines having the potential to generate approximately 1,500-2,000 MW of electricity or enough electricity to serve approximately 500,000 homes at peak demand. In December 2012, BOEM announced that it would auction approximately 113,000 acres off the Virginia coast as a single lease in 2013.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors 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 held 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 $128 million and $179 million as of December 31, 2012 and 2011, respectively. A hypothetical 10% unfavorable change in commodity prices of Dominion’s commodity-based financial derivative instruments held for trading purposes would have resulted in a decrease in fair value of approximately $18 million and $8 million as of December 31, 2012 and 2011, respectively.

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

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

Interest Rate Risk

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

Dominion and Virginia Power may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. As of December 31, 2012, Dominion and Virginia Power had $1.8 billion and $750 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $21 million and $9 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at December 31, 2012. As of December 31, 2011, Dominion and Virginia Power had $2.3 billion and $1.3 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $31 million and $15 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at December 31, 2011.

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

50

results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.

Investment Price Risk

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

Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $126 million and $54 million in 2012 and 2011, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2012 and 2011, Dominion recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $210 million and $52 million, respectively.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $53 million and $24 million in 2012 and 2011, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2012 and 2011, Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $89 million and $25 million, respectively.

Dominion sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power employees participate in these plans. Aggregate actual returns for Dominion’s pension and other postretirement plan assets were $743 million in 2012

and $273 million in 2011, versus expected returns of $509 million and $519 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the periodic cost recognized for employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. As of December 31, 2012 and 2011, a hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion’s plan assets would result in an increase in net periodic cost of approximately $13 million for pension benefits and $3 million for other postretirement benefits.

Risk Management Policies

Dominion and Virginia Power have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies of all subsidiaries, including Virginia Power. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and Dominion’s and Virginia Power’s December 31, 2012 provision for credit losses, management believes that it is unlikely that a material adverse effect on Dominion’s or Virginia Power’s financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

51

Item 8. Financial Statements and Supplementary Data

	Page No.
Dominion Resources, Inc.
Report of Independent Registered Public Accounting Firm		53
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010		54
Consolidated Statements of Comprehensive Income at December 31, 2012, 2011 and 2010 and for the years then ended		55
Consolidated Balance Sheets at December 31, 2012 and 2011		56
Consolidated Statements of Equity at December 31, 2012, 2011 and 2010 and for the years then ended		58
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010		59
Virginia Electric and Power Company
Report of Independent Registered Public Accounting Firm		60
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010		61
Consolidated Statements of Comprehensive Income at December  31, 2012, 2011 and 2010 and for the years then ended		62
Consolidated Balance Sheets at December 31, 2012 and 2011		63
Consolidated Statements of Common Shareholder’s Equity at December  31, 2012, 2011 and 2010 and for the years then ended		65
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010		66
Combined Notes to Consolidated Financial Statements		67

52

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Dominion Resources, Inc.

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of Dominion’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Resources, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Dominion’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2013 expressed an unqualified opinion on Dominion’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2013

53

Dominion Resources, Inc.

Consolidated Statements of Income

Year Ended December 31,	2012			2011(1)			2010(1)
(millions, except per share amounts)
Operating Revenue	$	13,093		$	14,145		$	14,927
Operating Expenses
Electric fuel and other energy-related purchases		3,748			4,097			4,034
Purchased electric capacity		387			454			453
Purchased gas		1,177			1,764			2,049
Other operations and maintenance(2)		4,868			3,322			3,448
Depreciation, depletion and amortization		1,186			1,066			1,035
Other taxes		571			548			524
Total operating expenses		11,937			11,251			11,543
Gain on sale of Appalachian E&P operations		—			—			2,467
Income from operations		1,156			2,894			5,851
Other income		223			178			170
Interest and related charges		882			867			826
Income from continuing operations including noncontrolling interests before income taxes		497			2,205			5,195
Income tax expense		146			754			2,112
Income from continuing operations including noncontrolling interests		351			1,451			3,083
Loss from discontinued operations(3)		(22	)		(25	)		(258	)
Net income including noncontrolling interests		329			1,426			2,825
Noncontrolling interests		27			18			17
Net income attributable to Dominion		302			1,408			2,808
Amounts attributable to Dominion:
Income from continuing operations, net of tax		324			1,433			3,066
Loss from discontinued operations, net of tax		(22	)		(25	)		(258	)
Net income attributable to Dominion		302			1,408			2,808
Earnings Per Common Share-Basic:
Income from continuing operations	$	0.57		$	2.50		$	5.21
Loss from discontinued operations		(0.04	)		(0.04	)		(0.44	)
Net income attributable to Dominion	$	0.53		$	2.46		$	4.77
Earnings Per Common Share-Diluted:
Income from continuing operations	$	0.57		$	2.49		$	5.20
Loss from discontinued operations		(0.04	)		(0.04	)		(0.44	)
Net income attributable to Dominion	$	0.53		$	2.45		$	4.76
Dividends declared per common share	$	2.11		$	1.97		$	1.83

(1) Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

(2) For 2012, includes impairment and other charges of $2.1 billion related to Brayton Point, Kincaid and Kewaunee. See Note 6 for additional information.

(3) Includes income tax benefit of $27 million, $9 million, and $34 million in 2012, 2011 and 2010, respectively.

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

54

Dominion Resources, Inc.

Consolidated Statements of Comprehensive Income

Year Ended December 31,	2012			2011			2010
(millions)
Net income including noncontrolling interests	$	329		$	1,426		$	2,825
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $5, $48 and $(52) tax		(8	)		(67	)		84
Changes in unrealized net gains on investment securities, net of $(68), $(7) and $(54) tax		108			11			89
Changes in net unrecognized pension and other postretirement benefit costs, net of $209, $147 and $40 tax		(330	)		(231	)		(18	)
Amounts reclassified to net income:
Net derivative (gains)-hedging activities, net of $34, $28 and $193 tax		(60	)		(38	)		(314	)
Net realized (gains) losses on investment securities, net of $16, $(4) and $9 tax		(25	)		6			(14	)
Net pension and other postretirement benefit costs, net of $(32), $(25) and $(38) tax		48			39			54
Total other comprehensive loss		(267	)		(280	)		(119	)
Comprehensive income including noncontrolling interests		62			1,146			2,706
Comprehensive income attributable to noncontrolling interests		27			18			17
Comprehensive income attributable to Dominion	$	35		$	1,128		$	2,689

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

55

Dominion Resources, Inc.

Consolidated Balance Sheets

At December 31,	2012			2011
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	248		$	102
Customer receivables (less allowance for doubtful accounts of $28 and $29)		1,621			1,780
Other receivables (less allowance for doubtful accounts of $4 and $8)		96			255
Inventories:
Materials and supplies		684			641
Fossil fuel		467			541
Gas stored		108			166
Derivative assets		518			705
Regulatory assets		203			541
Prepayments		326			262
Deferred income taxes		573			9
Other		296			428
Total current assets		5,140			5,430
Investments
Nuclear decommissioning trust funds		3,330			2,999
Investment in equity method affiliates		558			553
Restricted cash equivalents		33			141
Other		270			292
Total investments		4,191			3,985
Property, Plant and Equipment
Property, plant and equipment		43,364			42,033
Property, plant and equipment, VIE		957			957
Accumulated depreciation, depletion and amortization		(13,548	)		(13,320	)
Total property, plant and equipment, net		30,773			29,670
Deferred Charges and Other Assets
Goodwill		3,130			3,141
Pension and other postretirement benefit assets		702			681
Intangible assets		536			637
Regulatory assets		1,717			1,382
Other		649			688
Total deferred charges and other assets		6,734			6,529
Total assets	$	46,838		$	45,614

56

At December 31,	2012			2011
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	1,363		$	1,479
Securities due within one year, VIE		860			—
Short-term debt		2,412			1,814
Accounts payable		1,137			1,250
Accrued interest, payroll and taxes		636			648
Derivative liabilities		510			951
Regulatory liabilities		136			243
Other		709			577
Total current liabilities		7,763			6,962
Long-Term Debt
Long-term debt		15,478			14,785
Long-term debt, VIE		—			890
Junior subordinated notes		1,373			1,719
Total long-term debt		16,851			17,394
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		5,800			5,216
Asset retirement obligations		1,641			1,383
Pension and other postretirement benefit liabilities		1,831			962
Regulatory liabilities		1,514			1,324
Other		556			613
Total deferred credits and other liabilities		11,342			9,498
Total liabilities		35,956			33,854
Commitments and Contingencies (see Note 22)
Subsidiary Preferred Stock Not Subject To Mandatory Redemption		257			257
Equity
Common stock-no par(1)		5,493			5,180
Other paid-in capital		162			179
Retained earnings		5,790			6,697
Accumulated other comprehensive loss		(877	)		(610	)
Total common shareholders’ equity		10,568			11,446
Noncontrolling interest		57			57
Total equity		10,625			11,503
Total liabilities and equity	$	46,838		$	45,614

(1) 1 billion shares authorized; 576 million shares and 570 million shares outstanding at December 31, 2012 and 2011, respectively.

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

57

Dominion Resources, Inc.

Consolidated Statements of Equity

	Common Stock						Dominion Shareholders
	Shares			Amount			Other Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Shareholders’ Equity			Noncontrolling Interests			Total Equity
(millions)
December 31, 2009		599		$	6,525		$	185		$	4,686		$	(211	)	$	11,185		$	—		$	11,185
Net income including noncontrolling interests											2,825						2,825						2,825
Issuance of stock-employee and direct stock purchase plans		1			10												10						10
Stock awards and stock options exercised (net of change in unearned compensation)		2			80												80						80
Stock repurchases		(21	)		(900	)											(900	)					(900	)
Tax benefit from stock awards and stock options exercised								9									9						9
Dividends(1)											(1,093	)					(1,093	)					(1,093	)
Other comprehensive loss, net of tax														(119	)		(119	)					(119	)
December 31, 2010		581			5,715			194			6,418			(330	)		11,997			—			11,997
Net income including noncontrolling interests											1,425						1,425			1			1,426
Consolidation of noncontrolling interests(2)																	—			61			61
Stock awards and stock options exercised (net of change in unearned compensation)		1			49												49						49
Stock repurchases		(13	)		(601	)											(601	)					(601	)
Other stock issuances(3)		1			17			(17	)								—						—
Tax benefit from stock awards and stock options exercised								2									2						2
Dividends											(1,146	)(1)					(1,146	)		(5	)		(1,151	)
Other comprehensive loss, net of tax														(280	)		(280	)					(280	)
December 31, 2011		570			5,180			179			6,697			(610	)		11,446			57			11,503
Net income including noncontrolling interests											318						318			11			329
Issuance of stock-employee and direct stock purchase plans		4			246												246						246
Stock awards and stock options exercised (net of change in unearned compensation)		1			26												26						26
Other stock issuances(3)		1			41			(27	)								14						14
Tax benefit from stock awards and stock options exercised								10									10						10
Dividends											(1,225	)(1)					(1,225	)		(11	)		(1,236	)
Other comprehensive income, net of tax														(267	)		(267	)					(267	)
December 31, 2012		576		$	5,493		$	162		$	5,790		$	(877	)	$	10,568		$	57		$	10,625

(1) Includes subsidiary preferred dividends related to noncontrolling interests of $16 million in 2012 and $17 million in 2011 and 2010.

(2) See Note 15 for consolidation of a VIE in October 2011.

(3) Contains shares issued in excess of principal amounts related to converted securities. See Note 17 for further information on convertible securities.

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

58

Dominion Resources, Inc.

Consolidated Statements of Cash Flows

Year Ended December 31,	2012			2011			2010
(millions)
Operating Activities
Net income including noncontrolling interests	$	329		$	1,426		$	2,825
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
Impairment of generation assets (including discontinued operations)		2,089			283			194
Net reserves (payments) related to rate refunds		(151	)		3			(500	)
Contributions to pension plans		—			—			(650	)
Charges (payments) related to workforce reduction program		(9	)		(115	)		229
Depreciation, depletion and amortization (including nuclear fuel)		1,443			1,288			1,258
Deferred income taxes and investment tax credits		246			756			682
Gain on the sale of assets to Blue Racer		(81	)		—			—
Other adjustments		(155	)		(92	)		(40	)
Changes in:
Accounts receivable		292			365			(60	)
Inventories		33			(185	)		35
Deferred fuel and purchased gas costs, net		368			(3	)		(246	)
Prepayments		(85	)		(19	)		139
Accounts payable		(61	)		(413	)		119
Accrued interest, payroll and taxes		(12	)		(216	)		166
Other operating assets and liabilities		(109	)		(95	)		28
Net cash provided by operating activities		4,137			2,983			1,825
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(4,145	)		(3,652	)		(3,422	)
Proceeds from sale of Appalachian E&P operations		—			—			3,450
Proceeds from sale of Peoples		—			—			741
Proceeds from sales of securities		1,356			1,757			2,814
Purchases of securities		(1,392	)		(1,824	)		(2,851	)
Proceeds from Blue Racer		115			—			—
Restricted cash equivalents		108			259			(396	)
Other		118			139			83
Net cash provided by (used in) investing activities		(3,840	)		(3,321	)		419
Financing Activities
Issuance of short-term debt, net		598			429			91
Issuance of short-term notes		400			—			—
Issuance and remarketing of long-term debt		1,500			2,320			1,090
Repayment and repurchase of long-term debt		(1,675	)		(637	)		(1,492	)
Issuance of common stock		265			38			74
Repurchase of common stock		—			(601	)		(900	)
Common dividend payments		(1,209	)		(1,129	)		(1,076	)
Subsidiary preferred dividend payments		(16	)		(17	)		(17	)
Other		(14	)		(25	)		(2	)
Net cash provided by (used in) financing activities		(151	)		378			(2,232	)
Increase in cash and cash equivalents		146			40			12
Cash and cash equivalents at beginning of year		102			62			50
Cash and cash equivalents at end of year	$	248		$	102		$	62
Supplemental Cash Flow Information
Cash paid (received) during the year for:
Interest and related charges, excluding capitalized amounts	$	913		$	920		$	894
Income taxes		(58	)		166			991
Significant noncash investing and financing activities:
Accrued capital expenditures		388			328			240
Consolidation of VIE—assets at fair value		—			957			—
Consolidation of VIE—debt		—			896			—

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

59

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Virginia Electric and Power Company

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (“Virginia Power”) as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of Virginia Power’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Virginia Power’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2013

60

Virginia Electric and Power Company

Consolidated Statements of Income

Year Ended December 31,	2012		2011		2010
(millions)
Operating Revenue	$	7,226	$	7,246	$	7,219
Operating Expenses
Electric fuel and other energy-related purchases		2,368		2,506		2,495
Purchased electric capacity		386		452		449
Other operations and maintenance:
Affiliated suppliers		305		306		384
Other		1,161		1,437		1,361
Depreciation and amortization		782		718		671
Other taxes		232		222		218
Total operating expenses		5,234		5,641		5,578
Income from operations		1,992		1,605		1,641
Other income		96		88		100
Interest and related charges		385		331		347
Income from operations before income tax expense		1,703		1,362		1,394
Income tax expense		653		540		542
Net Income		1,050		822		852
Preferred dividends		16		17		17
Balance available for common stock	$	1,034	$	805	$	835

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

61

Virginia Electric and Power Company

Consolidated Statements of Comprehensive Income

Year Ended December 31,	2012			2011			2010
(millions)
Net income	$	1,050		$	822		$	852
Other comprehensive income (loss), net of taxes:
Net deferred losses on derivatives-hedging activities, net of $3, $3 and $1 tax		(5	)		(6	)		(1	)
Changes in unrealized net gains on nuclear decommissioning trust funds, net of $(7), $(1) and $(6) tax		13			2			9
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of $(2), $—and $4 tax		2			(1	)		(8	)
Net realized gains on nuclear decommissioning trust funds, net of $2, $—and $2 tax		(4	)		—			(2	)
Other comprehensive income (loss)		6			(5	)		(2	)
Comprehensive income	$	1,056		$	817		$	850

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

62

Virginia Electric and Power Company

Consolidated Balance Sheets

At December 31,	2012			2011
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	28		$	29
Customer receivables (less allowance for doubtful accounts of $10 and $11)		849			892
Other receivables (less allowance for doubtful accounts of $3 and $7)		51			145
Inventories (average cost method):
Materials and supplies		385			359
Fossil fuel		404			438
Prepayments		23			41
Regulatory assets		119			479
Deferred income taxes		92			—
Other		30			53
Total current assets		1,981			2,436
Investments
Nuclear decommissioning trust funds		1,515			1,370
Other		14			36
Total investments		1,529			1,406
Property, Plant and Equipment
Property, plant and equipment		30,631			28,626
Accumulated depreciation and amortization		(10,014	)		(9,615	)
Total property, plant and equipment, net		20,617			19,011
Deferred Charges and Other Assets
Intangible assets		181			183
Regulatory assets		396			399
Other		107			109
Total deferred charges and other assets		684			691
Total assets	$	24,811		$	23,544

63

At December 31,	2012		2011
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	418	$	616
Short-term debt		992		894
Accounts payable		430		405
Payables to affiliates		67		108
Affiliated current borrowings		435		187
Accrued interest, payroll and taxes		204		226
Derivative liabilities		33		135
Customer deposits		100		106
Regulatory liabilities		32		178
Deferred income taxes		—		91
Other		296		175
Total current liabilities		3,007		3,121
Long-Term Debt		6,251		6,246
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		3,879		3,180
Asset retirement obligations		705		624
Regulatory liabilities		1,285		1,095
Other		194		271
Total deferred credits and other liabilities		6,063		5,170
Total liabilities		15,321		14,537
Commitments and Contingencies (see Note 22)
Preferred Stock Not Subject to Mandatory Redemption		257		257
Common Shareholder’s Equity
Common stock-no par(1)		5,738		5,738
Other paid-in capital		1,113		1,111
Retained earnings		2,357		1,882
Accumulated other comprehensive income		25		19
Total common shareholder’s equity		9,233		8,750
Total liabilities and shareholder’s equity	$	24,811	$	23,544

(1) 500,000 shares authorized at December 31, 2012 and 2011; 274,723 shares outstanding at December 31, 2012 and 2011.

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

64

Virginia Electric and Power Company

Consolidated Statements of Common Shareholder’s Equity

	Common Stock				Other Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	Shares		Amount
(millions, except for shares)	(thousands)
Balance at December 31, 2009		242	$	4,738	$	1,110	$	1,299		$	26		$	7,173
Net income								852						852
Issuance of stock to Dominion		33		1,000										1,000
Dividends								(517	)					(517	)
Tax benefit from stock awards and stock options exercised						1								1
Other comprehensive loss, net of tax											(2	)		(2	)
Balance at December 31, 2010		275		5,738		1,111		1,634			24			8,507
Net income								822						822
Dividends								(574	)					(574	)
Other comprehensive loss, net of tax											(5	)		(5	)
Balance at December 31, 2011		275		5,738		1,111		1,882			19			8,750
Net income								1,050						1,050
Dividends								(575	)					(575	)
Tax benefit from stock awards and stock options exercised						2								2
Other comprehensive income, net of tax											6			6
Balance at December 31, 2012		275	$	5,738	$	1,113	$	2,357		$	25		$	9,233

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

65

Virginia Electric and Power Company

Consolidated Statements of Cash Flows

Year Ended December 31,	2012			2011			2010
(millions)
Operating Activities
Net income	$	1,050		$	822		$	852
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		927			838			782
Deferred income taxes and investment tax credits, net		502			496			609
Impairment of generation assets		—			228			—
Net reserves (payments) related to rate refunds		(151	)		3			(500	)
Contributions to pension plans		—			—			(302	)
Charges (payments) related to workforce reduction program		(4	)		(53	)		98
Other adjustments		(66	)		(40	)		(40	)
Changes in:
Accounts receivable		126			76			(9	)
Affiliated accounts receivable and payable		(2	)		(7	)		11
Inventories		8			(200	)		17
Deferred fuel expenses, net		378			12			(213	)
Prepayments		18			24			(10	)
Accounts payable		19			(117	)		108
Accrued interest, payroll and taxes		(22	)		12			1
Other operating assets and liabilities		(77	)		(70	)		5
Net cash provided by operating activities		2,706			2,024			1,409
Investing Activities
Plant construction and other property additions		(2,082	)		(1,885	)		(2,113	)
Purchases of nuclear fuel		(206	)		(205	)		(121	)
Purchases of securities		(638	)		(1,057	)		(1,211	)
Proceeds from sales of securities		626			1,030			1,192
Restricted cash equivalents		22			137			(165	)
Other		(4	)		33			(7	)
Net cash used in investing activities		(2,282	)		(1,947	)		(2,425	)
Financing Activities
Issuance of short-term debt, net		98			294			158
Issuance of affiliated current borrowings, net		248			85			1,101
Issuance and remarketing of long-term debt		450			235			605
Repayment and repurchase of long-term debt		(641	)		(91	)		(347	)
Common dividend payments		(559	)		(557	)		(500	)
Preferred dividend payments		(16	)		(17	)		(17	)
Other		(5	)		(2	)		2
Net cash provided by (used in) financing activities		(425	)		(53	)		1,002
Increase (decrease) in cash and cash equivalents		(1	)		24			(14	)
Cash and cash equivalents at beginning of year		29			5			19
Cash and cash equivalents at end of year	$	28		$	29		$	5
Supplemental Cash Flow Information
Cash paid (received) during the year for:
Interest and related charges, excluding capitalized amounts	$	376		$	376		$	349
Income taxes		225			(27	)		(101	)
Significant noncash investing and financing activities:
Accrued capital expenditures		242			199			136
Settlement of debt and issuance of common stock to Dominion		—			—			1,000

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

66

Combined Notes to Consolidated Financial Statements

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 North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s common stock is owned by Dominion. Dominion’s operations also include a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, an LNG import and storage facility in Maryland and regulated gas transportation and distribution operations in Ohio and West Virginia. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations.

Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are expected to be and are currently discontinued, which is discussed in Note 3. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 25 for further discussion of Dominion’s and Virginia Power’s operating segments.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

General

Dominion and Virginia Power 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, expenses and cash flows for the periods presented. Actual results may differ from those estimates.

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

Dominion and Virginia Power report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.

Dominion maintains pension and other postretirement benefit plans. Virginia Power participates in certain of these plans. See Note 21 for further information on these plans.

Certain amounts in the 2011 and 2010 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2012 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

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

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. The Companies collect sales, consumption and consumer utility taxes; however, these amounts are excluded from revenue. Dominion’s customer receivables at December 31, 2012 and 2011 included $411 million and $423 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2012 and 2011 included $348 million and $360 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers.

The primary types of sales and service activities reported as operating revenue for Dominion are as follows:

Ÿ Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

Ÿ Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;

Ÿ Regulated gas sales consist primarily of state-regulated retail natural gas sales and related distribution services;

Ÿ Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties;

Ÿ Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services and associated derivative activity. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; and

Ÿ Other revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes miscellaneous service revenue from electric and gas distribution operations, and gas processing and handling revenue.

The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:

Ÿ Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and

Ÿ Other revenue consists primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.

67

Combined Notes to Consolidated Financial Statements, Continued

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Where permitted by regulatory authorities, the differences between Virginia Power’s actual electric fuel and purchased energy expenses and Dominion’s purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.

Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 83% is currently subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.

Income Taxes

A consolidated federal income tax return is filed for Dominion and its subsidiaries, including Virginia Power. In addition, where applicable, combined income tax returns for Dominion and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed. Virginia Power participates in an intercompany tax sharing agreement with Dominion and its subsidiaries, and its current income taxes are based on its taxable income or loss, determined on a separate company basis.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

Dominion and Virginia Power recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the consolidated balance sheets and current payables are included in accrued interest, payroll and taxes on the consolidated balance sheets, except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities.

Dominion and Virginia Power recognize changes in estimated interest payable on net underpayments of income taxes in interest expense. Changes in interest receivable related to net overpay-

ments of income taxes and estimated penalties that may result from the settlement of some uncertain tax positions are recognized in other income. In its Consolidated Statements of Income for 2012, Dominion recognized interest income of $8 million and interest expense of $3 million and a reduction in penalties of less than $1 million. In 2011, Dominion recognized interest income of $12 million and interest expense of $7 million and a reduction in penalties of less than $1 million. In 2010, Dominion recognized a reduction in interest expense of $18 million and a reduction in penalties of less than $1 million. Dominion had accrued interest receivable of $5 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2012 and interest receivable of $48 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2011.

Virginia Power’s interest and penalties were immaterial in 2012 and 2010. In 2011, Virginia Power recognized interest income of $12 million, and penalties were immaterial. Virginia Power had accrued interest receivable of $17 million at December 31, 2011.

At December 31, 2012, Virginia Power’s Consolidated Balance Sheet included $10 million of federal income taxes payable and $36 million of noncurrent federal and state income taxes payable.

At December 31, 2011, Virginia Power’s Consolidated Balance Sheet included $18 million of current federal income taxes receivable, $34 million of current state income taxes payable and $110 million of noncurrent federal and state income taxes payable.

Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 2012 and 2011, Dominion’s accounts payable included $53 million and $75 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 2012 and 2011, Virginia Power’s accounts payable included $30 million and $40 million, respectively, of checks outstanding but not yet presented for payment. For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Derivative Instruments

Dominion and Virginia Power use derivative instruments such as futures, swaps, forwards, options and FTRs to manage the commodity, currency exchange and financial market risks of their business operations.

All derivatives, other than those for which an exception applies, are reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are

68

reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.

Dominion and Virginia Power do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion had margin assets of $212 million and $319 million associated with cash collateral at December 31, 2012 and 2011, respectively. Dominion had margin liabilities of $4 million and $66 million associated with cash collateral at December 31, 2012 and 2011, respectively. Virginia Power had margin assets of $18 million and $41 million associated with cash collateral at December 31, 2012 and 2011, respectively. Virginia Power’s margin liabilities associated with cash collateral were not material at December 31, 2012 and 2011.

To manage price risk, Dominion and Virginia Power hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. As part of Dominion’s strategy to market energy and manage related risks, it also manages a portfolio of commodity-based financial derivative instruments held for trading purposes. Dominion uses established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and uses various derivative instruments to reduce risk by creating offsetting market positions.

Statement of Income Presentation:

Ÿ Derivatives Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis.

Ÿ Derivatives Not Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses or interest and related charges based on the nature of the underlying risk.

In Virginia Power’s generation operations, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.

DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS

Dominion and Virginia Power designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, Dominion and Virginia Power formally document the relationship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using the hedging instrument. The Companies assess whether the hedg-

ing relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges—A majority of Dominion’s and Virginia Power’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and other energy-related products. The Companies also use foreign currency contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which Dominion and Virginia Power are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Fair Value Hedges—Dominion also uses fair value hedges to mitigate the fixed price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, Dominion and Virginia Power have designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Derivative gains and losses from the hedged item are reclassified to earnings when the hedged item is included in earnings, or earlier, if the hedged item no longer qualifies for hedge accounting. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting.

See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.

Property, Plant and Equipment

Property, plant and equipment, including additions and replacements is recorded at original cost, consisting of labor and materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as it is incurred.

In 2012, 2011 and 2010, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $91 million, $85 million and $102 million, respectively. In 2012, 2011 and

69

Combined Notes to Consolidated Financial Statements, Continued

2010, Virginia Power capitalized AFUDC to property, plant and equipment of $31 million, $31 million and $61 million, respectively. Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2012, 2011 and 2010, Virginia Power recorded $37 million, $20 million and $13 million of AFUDC related to these projects, respectively.

For Virginia Power property subject to cost-of-service rate regulation, including electric distribution, electric transmission, and generation property and for certain Dominion natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be retired or abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be retired or abandoned.

For Dominion and Virginia Power property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. Dominion’s and Virginia Power’s depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2012		2011		2010
(percent)
Dominion
Generation		2.62		2.68		2.59
Transmission		2.17		2.26		2.24
Distribution		3.17		3.19		3.20
Storage		2.59		2.64		2.75
Gas gathering and processing		2.49		2.52		2.39
General and other		4.55		4.66		4.60
Virginia Power
Generation		2.62		2.68		2.59
Transmission		1.98		2.03		1.94
Distribution		3.32		3.33		3.33
General and other		4.32		4.38		4.28

Dominion’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

Asset	Estimated Useful Lives
Merchant generation—nuclear		34 – 44 years
Merchant generation—other		27 – 40 years
General and other		5 – 59 years

Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.

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, Dominion no longer has any significant gas and oil properties subject to the ceiling test calculation.

In 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 and recognized a gain from the sale of substantially all of its Appalachian E&P operations, as discussed in Note 3.

Emissions Allowances

Emissions allowances permit the holder of the allowance to emit certain gaseous by-products of fossil fuel combustion, including SO₂, NO_X and CO₂. SO₂ and NO_X emissions allowances are issued to Dominion and Virginia Power by the EPA and may also be purchased and sold via third party contracts. CO₂ emissions allowances are available for purchase by Dominion through quarterly auctions held by participating RGGI states. Compliance with the RGGI requirements only applies to certain of Dominion’s merchant power stations located in the Northeast.

Allowances held may be transacted with third parties or consumed as these emissions are generated. Allowances allocated to or acquired by the Companies’ generation operations are held primarily for consumption.

Allowances held for consumption are classified as intangible assets in the Consolidated Balance Sheets. Carrying amounts are based on the cost to acquire the allowances or, in the case of a business combination, on the fair values assigned to them in the allocation of the purchase price of the acquired business. A portion of Dominion’s and Virginia Power’s SO₂ and NO_X allowances are issued by the EPA at zero cost.

These allowances are amortized in the periods the emissions are generated, with the amortization reflected in depreciation, depletion and amortization in the Consolidated Statements of Income. Purchases and sales of these allowances are reported as investing activities in the Consolidated Statements of Cash Flows and gains or losses resulting from sales are reported in other operations and maintenance expense in the Consolidated Statements of Income. See Note 6 for discussion of impairments related to emissions allowances.

Long-Lived and Intangible Assets

Dominion and Virginia Power perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for a discussion of impairments related to certain long-lived assets and intangible assets with finite lives.

70

Regulatory Assets and Liabilities

The accounting for Dominion’s regulated gas and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made.

Asset Retirement Obligations

Dominion and Virginia Power recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is

estimated using discounted cash flow analyses. Dominion reports accretion of AROs associated with its natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Virginia Power reports accretion of AROs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Accretion of all other AROs is reported in other operations and maintenance expense in the Consolidated Statements of Income.

Amortization of Debt Issuance Costs

Dominion and Virginia Power defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized over the lives of the new issuances.

Investments

MARKETABLE EQUITY AND DEBT SECURITIES

Dominion accounts for and classifies investments in marketable equity and debt securities as trading or available-for-sale securities.

Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities.

Ÿ Trading securities include marketable equity and debt securities held by Dominion in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

Ÿ Available-for-sale securities include all other marketable equity and debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other available-for-sale securities, including those held in Dominion’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

In determining realized gains and losses for marketable equity and debt securities, the cost basis of the security is based on the specific identification method.

NON-MARKETABLE INVESTMENTS

Dominion and Virginia Power account for illiquid and privately held securities for which market prices or quotations are not readily available under either the equity or cost method. Non-marketable investments include:

Ÿ Equity method investments when Dominion and Virginia Power have the ability to exercise significant influence, but not control, over the investee. Dominion’s investments are included in investments in equity method affiliates and Virginia Power’s investments are included in other investments in their Consolidated Balance Sheets. Dominion and Virginia Power record equity method adjustments in other income in the Consolidated Statements of Income including: their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

Ÿ Cost method investments when Dominion and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion’s and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds.

71

Combined Notes to Consolidated Financial Statements, Continued

OTHER-THAN-TEMPORARY IMPAIRMENT

Dominion and Virginia Power periodically review their investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period.

Decommissioning Trust Investments—Special Considerations

Ÿ The recognition provisions of the FASB’s other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities.

Ÿ Debt Securities—Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, the Companies record the credit loss in earnings and any remaining portion of the unrealized loss in other comprehensive income. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

Ÿ Equity securities and other investments—Dominion’s and Virginia Power’s method of assessing other-than-temporary declines requires demonstrating the ability to hold individual securities for a period of time sufficient to allow for the anticipated recovery in their market value prior to the consideration of the other criteria mentioned above. Since the Companies have limited ability to oversee the day-to-day management of nuclear decommissioning trust fund investments, they do not have the ability to ensure investments are held through an anticipated recovery period. Accordingly, they consider all equity and other securities as well as non-marketable investments held in nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired.

Inventories

Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory used in East Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at $24 million and $48 million at December 31, 2012 and December 31, 2011, respectively. Based on the average price of gas purchased during 2012 and 2011, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $69 million and $86 million, respectively. Stored gas inventory held by Hope and certain nonregulated gas operations is valued using the weighted-average cost method.

Gas Imbalances

Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion values these imbalances due to, or

from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion from other parties are reported in other current assets and imbalances that Dominion owes to other parties are reported in other current liabilities in the Consolidated Balance Sheets.

Goodwill

Dominion evaluates goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.

NOTE 3. DISPOSITIONS

Sale of Salem Harbor and State Line

In August 2012, Dominion completed the sale of Salem Harbor. In the second quarter of 2012, the assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell. During the second quarter of 2012, Dominion completed the sale of State Line, which ceased operations in March 2012. See Note 6 for impairments related to these power stations.

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

Year Ended December 31,	2012			2011			2010
(millions)
Operating revenue	$	57		$	233		$	269
Loss before income taxes(1)		(49	)		(34	)		(158	)

(1) Includes long-lived asset impairment charges of $55 million and $194 million in 2011 and 2010, respectively.

Sale of Appalachian E&P Operations

In April 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations to a 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 includes 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 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.

72

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:

Year Ended December 31,	2010
(millions)
Operating revenue	$	67
Loss before income taxes		(134	)(1)

(1) Includes a loss and other charges related to the sale of Peoples.

NOTE 4. OPERATING REVENUE

Dominion’s and Virginia Power’s operating revenue consists of the following:

Year Ended December 31,	2012		2011		2010
(millions)
Dominion
Electric sales:
Regulated	$	7,102	$	7,114	$	7,123
Nonregulated		2,742		3,100		3,559
Gas sales:
Regulated		250		287		308
Nonregulated		1,071		1,635		2,010
Gas transportation and storage		1,401		1,506		1,493
Other		527		503		434
Total operating revenue	$	13,093	$	14,145	$	14,927
Virginia Power
Regulated electric sales	$	7,102	$	7,114	$	7,123
Other		124		132		96
Total operating revenue	$	7,226	$	7,246	$	7,219

NOTE 5. INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. Dominion and Virginia Power are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

On January 2, 2013, U.S. federal legislation was enacted that provides an extension of the 50 percent bonus depreciation allowance for qualifying capital expenditures incurred through 2013.

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

Changes in tax treatment elected by Dominion or required by the regulations will impact income taxes payable, cash flows from operations and deferred taxes. Except to the extent the implementation impacts deferred taxes and, therefore, the rate base used to establish customer rates for regulated utilities, results of operations are not expected to be materially affected.

Continuing Operations

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

	Dominion(1)									Virginia Power(2)
Year Ended December 31,	2012			2011			2010			2012			2011			2010
(millions)
Current:
Federal	$	(117	)	$	3		$	894		$	70		$	(35	)	$	(78	)
State		80			9			309			81			79			10
Total current expense (benefit)		(37	)		12			1,203			151			44			(68	)
Deferred:
Federal		214			694			818			482			484			537
State		(30	)		50			93			21			13			74
Total deferred expense		184			744			911			503			497			611
Amortization of deferred investment tax credits		(1	)		(2	)		(2	)		(1	)		(1	)		(1	)
Total income tax expense	$	146		$	754		$	2,112		$	653		$	540		$	542

(1) In 2012, Dominion’s current federal income tax benefit includes a benefit related to the carryback of its current year operating loss, and deferred state income tax benefit reflects the impact of Brayton Point, Kincaid and Kewaunee impairment charges. In 2011, Dominion’s federal income tax expense includes a benefit related to its current year operating loss that is expected to be used in future years, and state income tax expense reflects changes in the amount of income apportioned among states, higher tax credits, claims for refunds and previously unrecognized tax benefits due to the expiration of statutes of limitations.

(2) In 2011, Virginia Power’s federal income tax expense includes a benefit related to a portion of its current year operating loss that is expected to be used in future years. Also, in 2011 and 2010, Virginia Power’s federal income tax expense reflects the amounts of current year operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

73

Combined Notes to Consolidated Financial Statements, Continued

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
Year Ended December 31,	2012			2011			2010			2012			2011			2010
U.S. statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		8.1			1.8			5.1			3.9			4.4			3.8
Valuation allowances		(1.5	)		—			(0.2	)		—			—			—
Production tax credits		(2.4	)		(0.6	)		(0.3	)		—			—			—
Amortization of investment tax credits		(0.3	)		(0.1	)		—			(0.1	)		(0.1	)		(0.1	)
AFUDC—equity		(4.1	)		(0.6	)		(0.4	)		(0.9	)		(0.8	)		(1.1	)
Employee stock ownership plan deduction		(3.1	)		(0.7	)		(0.3	)		—			—			—
Goodwill		0.4			—			0.9			—			—			—
Legislative change		—			—			1.1			—			—			1.1
Other, net		(2.8	)		(0.6	)		(0.2	)		0.4			1.2			0.2
Effective tax rate		29.3	%		34.2	%		40.7	%		38.3	%		39.7	%		38.9	%

Dominion’s effective tax rate in 2012 reflects the amplified effect of permanent differences due to lower pre-tax income, as well as the state tax impact of Brayton Point, Kincaid and Kewaunee impairment charges. The rate also reflects a $20 million reduction of a valuation allowance related to state operating loss carryforwards attributable to Fairless and a $14 million increase in valuation allowance related to Brayton Point state credit carryforwards. After considering the results of Fairless’ operations in recent years and a forecast of future operating results reflecting Dominion’s planned purchase of the facility, Dominion has concluded that it is more likely than not that the tax benefit of the operating losses will be realized. Significant assumptions include future commodity prices, in particular, those for electric energy produced by Fairless and those for natural gas, as compared to other fuels used for the generation of electricity, which will significantly influence the extent to which Fairless is dispatched by PJM. Also, in connection with its intention to sell Brayton Point, Dominion evaluated state tax credits previously recognized for the power station and recorded a $14 million increase in valuation allowance related to credit carryforwards and a $14 million deferred tax liability, representing recapture of credits claimed in prior years that would result upon completion of a sale. Dominion will continue to evaluate the likelihood of realizing these tax benefits on a quarterly basis.

Dominion’s and Virginia Power’s effective tax rates in 2010 reflect reductions of deferred tax assets of $57 million and $17 million, respectively, 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 includes higher state income taxes and the impact of goodwill written off that is not deductible for tax purposes associated with the sale of the Appalachian E&P operations.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

The Companies’ deferred income taxes consist of the following:

	Dominion						Virginia Power
At December 31,	2012			2011			2012			2011
(millions)
Deferred income taxes:
Total deferred income tax assets	$	2,505		$	2,229		$	466		$	503
Total deferred income tax liabilities		7,716			7,424			4,238			3,759
Total net deferred income tax liabilities	$	5,211		$	5,195		$	3,772		$	3,256
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	4,601		$	4,008		$	3,394		$	2,758
Nuclear decommissioning		994			913			407			374
Deferred state income taxes		474			493			265			243
Federal benefit of deferred state income taxes		(166	)		(173	)		(93	)		(85	)
Deferred fuel, purchased energy and gas costs		3			161			(16	)		144
Pension benefits		231			396			(17	)		8
Other postretirement benefits		(171	)		(167	)		(7	)		(13	)
Loss and credit carryforwards		(656	)		(577	)		(77	)		(55	)
Reserve for rate proceedings		—			(54	)		—			(54	)
Partnership basis differences		174			274			—			—
Valuation allowances		93			96			—			—
Other		(366	)		(175	)		(84	)		(64	)
Total net deferred income tax liabilities	$	5,211		$	5,195		$	3,772		$	3,256

At December 31, 2012, Dominion had the following deductible loss and credit carryforwards:

Ÿ Federal loss carryforwards of $1.1 billion that expire if unutilized during the period 2021 through 2031;

Ÿ Federal production tax credits of $26 million that expire if unutilized through 2032;

Ÿ State loss carryforwards of $1.4 billion that expire if unutilized during the period 2014 through 2032. A valuation allowance on $857 million of these carryforwards has been established;

Ÿ State minimum tax credits of $96 million that do not expire; and

Ÿ State investment tax credits of $28 million that expire if unutilized through 2016. A valuation allowance on $21 million of these credits has been established for credits that are not expected to be utilized.

At December 31, 2012, Virginia Power had federal loss carryforwards of $220 million that expire if unutilized through 2031.

Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. The amount of tax return positions that are not recognized in the financial statements is disclosed as unrecognized tax benefits. These unrecognized tax benefits may impact the financial statements by increasing income taxes payable, reducing

74

tax refunds receivable or changing deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, an increase in taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities.

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:

	Dominion									Virginia Power
	2012			2011			2010			2012			2011			2010
(millions)
Balance at January 1	$	347		$	307		$	291		$	114		$	117		$	121
Increases—prior period positions		28			127			34			4			22			4
Decreases—prior period positions		(106	)		(119	)		(75	)		(80	)		(51	)		(33	)
Increases—current period positions		43			64			61			24			47			25
Decreases—current period positions		—			(21	)		—			—			(21	)		—
Settlements with tax authorities		(4	)		—			—			(4	)		—			—
Expiration of statutes of limitation		(15	)		(11	)		(4	)		(1	)		—			—
Balance at December 31	$	293		$	347		$	307		$	57		$	114		$	117

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from claims for tax benefits, or portions thereof, that may not be realized, remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitation. For Dominion and its subsidiaries, these unrecognized tax benefits were $167 million, $184 million and $133 million at December 31, 2012, 2011 and 2010, respectively. For Dominion, the change in these unrecognized tax benefits increased income tax expense by $1 million, $51 million and $38 million in 2012, 2011 and 2010, respectively. For Virginia Power, these unrecognized tax benefits were $13 million, $20 million and $14 million at December 31, 2012, 2011 and 2010, respectively. For Virginia Power, the change in these unrecognized tax benefits increased income tax expense by $1 million, $6 million and by less than $1 million in 2012, 2011 and 2010, respectively.

For Dominion and its subsidiaries, the U.S. federal statute of limitations has expired for years prior to 2008. For prior years, Dominion had reserved the right to pursue refunds related to the calculation of interest to be capitalized in connection with improvements to in-service plant and equipment for the years 1995 through 2007. The IRS position had provided that capitalized interest must also be computed on the adjusted tax basis of in-service assets that are idled while making improvements to them. In response to litigation initiated by Dominion in March 2008, the U.S. Court of Federal Claims ruled in February 2011, sustaining the IRS position. In July 2011, Dominion filed an appeal with the United States Court of Appeals for the Federal Circuit and, in May 2012, the U.S. Court of Appeals for the Federal Circuit ruled in favor of Dominion. The resolution of this matter did not have a material impact on the Companies’ cash flows, results of operations or financial condition.

In January 2012, the Appellate Division of the IRS informed Dominion that the Joint Committee had completed its review of the settlement of tax years 2004 and 2005 for Dominion and its

consolidated subsidiaries. Since the measurement of unrecognized tax benefits in 2011 considered the results of completed settlement negotiations, Dominion’s results of operations in 2012 were not affected.

In April 2012, the IRS issued its Revenue Agent Report for Dominion’s consolidated tax returns for tax years 2006 and 2007, reflecting the resolution of all issues, except the capitalized interest on idle property issue that was in litigation at that time but later resolved as discussed above.

The IRS examination of tax years 2008, 2009 and 2010 began in the first quarter of 2012 and was later expanded to include examination of the 2011 tax year. The audit is expected to be concluded in late 2013.

It is reasonably possible that settlements with and payments to tax authorities in 2013 and the expiration of statutes of limitations could reduce unrecognized tax benefits for Dominion and Virginia Power by up to $65 million and $35 million, respectively. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, Dominion’s earnings could increase by up to $10 million, and Virginia Power’s earnings would not be affected.

Otherwise, with regard to 2012 and prior years, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2013.

For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows:

State	Earliest Open Tax Year
Pennsylvania		2009
Connecticut		2009
Massachusetts		2008
Virginia(1)		2009
West Virginia		2009

(1) Virginia is the only state considered major for Virginia Power’s operations.

Dominion and Virginia Power are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are subject to examination.

Discontinued Operations

Dominion’s effective tax rate for 2012 reflects the dispositions of State Line and Salem Harbor.

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

Dominion’s effective tax rate for 2010 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.

75

Combined Notes to Consolidated Financial Statements, Continued

NOTE 6. FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of Dominion’s and Virginia Power’s own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion and Virginia Power apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, and nuclear decommissioning trust and other investments including those held in Dominion’s rabbi, pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above. These credit adjustments are currently not material to the derivative fair values.

Inputs and Assumptions

The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, they consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases they must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect their market assumptions.

Dominion’s and Virginia Power’s commodity derivative valuations are prepared by the ERM department. The ERM department reports directly to the Companies’ CFO. The ERM department creates a daily file containing market valuations for the Companies’ derivative transactions. The inputs that go into the market valuations are transactional information stored in the systems of record and market pricing information that resides in data warehouses. The majority of forward prices are automatically uploaded into the data warehouses from various third-party sources. Inputs obtained from third-party sources are evaluated for

reliability considering the reputation, independence, market presence, and methodology used by the third-party. If forward prices are not available from third-party sources, then the ERM department models the forward prices based on other available market data. A team consisting of risk management and risk quantitative analysts meets each business day to assess the validity of market prices and valuations. During this meeting, the changes in market valuations from period to period are examined and qualified against historical expectations. If any discrepancies are identified during this process, the mark-to-market valuations or the market pricing information is evaluated further and adjusted, if necessary.

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, the Companies generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. The Companies use other option models under special circumstances, including a Spread Approximation Model when contracts include different commodities or commodity locations and a Swing Option Model when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.

The inputs and assumptions used in measuring fair value include the following:

For commodity and foreign currency derivative contracts:

Ÿ Forward commodity prices

Ÿ Forward foreign currency prices

Ÿ Transaction prices

Ÿ Price volatility

Ÿ Volumes

Ÿ Commodity location

Ÿ Interest rates

Ÿ Credit quality of counterparties and Dominion and Virginia Power

Ÿ Credit enhancements

Ÿ Time value

For interest rate derivative contracts:

Ÿ Interest rate curves

Ÿ Credit quality of counterparties and Dominion and Virginia Power

Ÿ Volumes

Ÿ Credit enhancements

Ÿ Time value

For investments:

Ÿ Quoted securities prices and indices

Ÿ Securities trading information including volume and restrictions

Ÿ Maturity

Ÿ Interest rates

Ÿ Credit quality

Ÿ NAV (only for alternative investments)

76

Dominion and Virginia Power regularly evaluate and validate the inputs used to estimate fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities and investments in which the Companies transact.

Levels

The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

Ÿ Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as the majority of exchange-traded derivatives, and exchange-listed equities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion.

Ÿ Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps, interest rate swaps, foreign currency forwards and options, restricted cash equivalents, and certain Treasury securities, money market funds, and corporate, state and municipal debt securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion.

Ÿ Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for Dominion and Virginia Power consist of long-dated commodity derivatives, FTRs and other modeled commodity derivatives. Additional instruments categorized in Level 3 for Dominion include NGLs and natural gas peaking options and alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments, held in benefit plan trust funds.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

For derivative contracts, Dominion and Virginia Power recognize transfers among Level 1, Level 2 and Level 3 based on fair

values as of the first day of the month in which the transfer occurs. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.

Level 3 Valuations

Fair value measurements are categorized as Level 3 when a significant amount of price or other inputs that are considered to be unobservable are used in their valuations. Long-dated commodity derivatives are generally based on unobservable inputs due to the length of time to settlement and the absence of market activity and are therefore categorized as Level 3. For NGL derivatives, market illiquidity requires a valuation based on proxy markets that do not always correlate to the actual instrument, therefore they are categorized as Level 3. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from ISO auctions, which are generally not considered to be liquid markets. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets. Alternative investments are categorized as Level 3 due to the absence of quoted market prices, illiquidity and the long-term nature of these assets. These investments are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date.

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

77

Combined Notes to Consolidated Financial Statements, Continued

The following table presents Dominion’s quantitative information about Level 3 fair value measurements. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility, price correlations, load shaping, and usage factors.

	Fair Value (millions)		Valuation Techniques	Unobservable Input				Range		Weighted Average(1)
At December 31, 2012
Assets:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	13	Discounted Cash Flow		Market Price (per Dth)	(3	)		(1) – 6		3
Electricity		6	Discounted Cash Flow		Market Price (per MWh)	(3	)		30 – 85		50
FTRs		5	Discounted Cash Flow		Market Price (per MWh)	(3	)		(6) – 7		1
Capacity		7	Discounted Cash Flow		Market Price (per MW)	(3	)		95 – 115		101
Liquids(8)		21	Discounted Cash Flow		Market Price (per Gal)	(3	)		0 – 3		1
Physical and Financial Options:
Natural Gas		5	Option Model		Market Price (per Dth)	(3	)		3 – 5		4
					Price Volatility	(4	)		21% – 36%		24	%
					Price Correlation	(5	)		73% – 73%		73	%
Full Requirements Contracts:
Electricity		27	Discounted Cash Flow		Market Price (per MWh)	(3	)		8 – 439(9)		40
					Load Shaping	(6	)		0% – 10%		5	%
					Usage Factor	(7	)		2% – 16%		8	%
Total assets	$	84
Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	18	Discounted Cash Flow		Market Price (per Dth)	(3	)		(1) – 18		3
Electricity		1	Discounted Cash Flow		Market Price (per MWh)	(3	)		25 – 65		39
FTRs		3	Discounted Cash Flow		Market Price (per MWh)	(3	)		(1) – 18		0
Liquids(8)		25	Discounted Cash Flow		Market Price (per Gal)	(3	)		1 – 3		2
Physical and Financial Options:
Natural Gas(2)		12	Option Model		Market Price (per Dth)	(3	)		3 – 8		5
					Price Volatility	(4	)		21% – 36%		32	%
					Price Correlation	(5	)		99%		99	%
Total liabilities	$	59

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

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

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

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

(8) Includes NGLs.

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

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

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

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

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

Nonrecurring Fair Value Measurements

MERCHANT POWER STATIONS

In the third quarter of 2012, Dominion decided to pursue the sale of Brayton Point and Kincaid, as well as its 50% interest in Elwood, which is an equity method investment. Since Dominion is unlikely to operate the Brayton Point and Kincaid facilities

through their estimated useful lives, Dominion evaluated these power stations for recoverability under a probability weighted approach and concluded that the carrying values of these facilities were not impaired as of September 30, 2012.

At December 31, 2012, Dominion updated its recoverability analysis for Brayton Point and Kincaid to reflect bids received and an updated probability weighting. As a result of this updated evaluation, Dominion recorded an impairment charge of approximately $1.6 billion ($1.0 billion after-tax), which is included in other operations and maintenance expense in its Consolidated Statement of Income, to write down Brayton Point’s and Kincaid’s long-lived assets to their estimated fair value of approximately $216 million. Dominion used a market approach to estimate the fair value of Brayton Point’s and Kincaid’s long-lived assets. This was considered a Level 2 fair value measurement given it was based on bids received.

Any sale of Brayton Point, Kincaid, or Dominion’s 50% interest in Elwood would be subject to the approval of Dominion’s Board of Directors, as well as applicable regulatory approvals.

78

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

As a result of this evaluation in September 2012, Dominion recorded impairment and other charges of $435 million ($281 million after-tax) largely reflected in other operations and maintenance expense in its Consolidated Statement of Income. This primarily reflects a $378 million ($244 million after-tax) charge for the full impairment of Kewaunee’s long-lived assets, a write down of materials and supplies inventories of $33 million ($21 million after-tax), and a $24 million ($16 million after-tax) charge related to severance costs.

The decision to decommission Kewaunee was approved by Dominion’s Board of Directors in October 2012 after consideration of the factors discussed above, which made it uneconomic for Kewaunee to continue operations. The station is expected to cease power production in the second quarter of 2013 and commence decommissioning activities. Following station shutdown, Dominion plans to meet its obligations to the two utilities that purchase Kewaunee’s generation through market purchases, until the power purchase agreements expire in December 2013.

In 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 ($107 million after-tax), which is now reflected in loss from discontinued operations in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of $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), which is now reflected in loss from discontinued operations in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of less than $1 million. State Line was retired in March 2012 and sold in the second quarter of 2012.

In December 2010, Dominion recorded an impairment charge of $31 million ($20 million after-tax), which is now reflected in loss from discontinued operations in its Consolidated Statement of Income, to write down the long-lived assets of Salem Harbor to their estimated fair value of less than $1 million as a result of profitability issues.

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 and Salem Harbor’s long-lived assets in these 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.

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

EMISSIONS ALLOWANCES

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 22. 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 had 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

79

Combined Notes to Consolidated Financial Statements, Continued

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.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion’s pension and other postretirement benefit plans are presented in Note 21.

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 December 31, 2012
Assets:
Derivatives:
Commodity	$	12	$	639	$	84	$	735
Interest rate		—		93		—		93
Investments(1):
Equity securities:
U.S.:
Large Cap		1,973		—		—		1,973
Other		59		—		—		59
Non-U.S.:
Large Cap		12		—		—		12
Fixed Income:
Corporate debt instruments		—		325		—		325
U.S. Treasury securities and agency debentures		391		152		—		543
State and municipal		—		315		—		315
Other		—		7		—		7
Cash equivalents and other		13		67		—		80
Restricted cash equivalents		—		33		—		33
Total assets	$	2,460	$	1,631	$	84	$	4,175
Liabilities:
Derivatives:
Commodity	$	8	$	528	$	59	$	595
Interest rate		—		66		—		66
Total liabilities	$	8	$	594	$	59	$	661

	Level 1		Level 2		Level 3		Total
(millions)
At December 31, 2011
Assets:
Derivatives:
Commodity	$	44	$	828	$	93	$	965
Interest rate		—		105		—		105
Investments(1):
Equity securities:
U.S.:
Large Cap		1,718		—		—		1,718
Other		51		—		—		51
Non-U.S.:
Large Cap		10		—		—		10
Fixed Income:
Corporate debt instruments		—		332		—		332
U.S. Treasury securities and agency debentures		277		181		—		458
State and municipal		—		329		—		329
Other		—		23		—		23
Cash equivalents and other		—		60		—		60
Restricted cash equivalents		—		141		—		141
Total assets	$	2,100	$	1,999	$	93	$	4,192
Liabilities:
Derivatives:
Commodity	$	10	$	714	$	164	$	888
Interest rate		—		269		—		269
Total liabilities	$	10	$	983	$	164	$	1,157

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

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:

	2012			2011			2010
(millions)
Balance at January 1,	$	(71	)	$	(50	)	$	(66	)
Total realized and unrealized gains (losses):
Included in earnings		(15	)		(77	)		43
Included in other comprehensive income (loss)		101			14			(49	)
Included in regulatory assets/liabilities		30			(42	)		24
Settlements		47			88			(38	)
Transfers out of Level 3		(67	)		(4	)		36
Balance at December 31,	$	25		$	(71	)	$	(50	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$	42		$	22		$	(4	)

80

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

	Operating Revenue			Electric Fuel and Energy Purchases			Purchased Gas			Total
(millions)
Year Ended December 31, 2012
Total gains (losses) included in earnings	$	35		$	(50	)	$	—		$	(15	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date		42			—			—			42
Year Ended December 31, 2011
Total gains (losses) included in earnings	$	(32	)	$	(45	)	$	—		$	(77	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date		22			—			—			22
Year Ended December 31, 2010
Total gains (losses) included in earnings	$	(4	)	$	51		$	(4	)	$	43
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date		(4	)		—			—			(4	)

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 December 31, 2012
Assets:
Derivatives:
Commodity	$	—	$	1	$	5	$	6
Investments(1):
Equity securities:
U.S.:
Large Cap		779		—		—		779
Other		27		—		—		27
Fixed Income:
Corporate debt instruments		—		196		—		196
U.S. Treasury securities and agency debentures		168		66		—		234
State and municipal		—		118		—		118
Other		—		1		—		1
Cash equivalents and other		7		31		—		38
Restricted cash equivalents		—		10		—		10
Total assets	$	981	$	423	$	5	$	1,409
Liabilities:
Derivatives:
Commodity	$	—	$	6	$	3	$	9
Interest rate		—		25		—		25
Total Liabilities	$	—	$	31	$	3	$	34

	Level 1		Level 2		Level 3		Total
(millions)
At December 31, 2011
Assets:
Derivatives:
Commodity	$	—	$	—	$	2	$	2
Investments(1):
Equity securities:
U.S.:
Large Cap		679		—		—		679
Other		23		—		—		23
Fixed Income:
Corporate debt instruments		—		214		—		214
U.S. Treasury securities and agency debentures		107		63		—		170
State and municipal		—		125		—		125
Other		—		16		—		16
Cash equivalents and other		—		40		—		40
Restricted cash equivalents		—		32		—		32
Total assets	$	809	$	490	$	2	$	1,301
Liabilities:
Derivatives:
Commodity	$	—	$	17	$	30	$	47
Interest rate		—		100		—		100
Total Liabilities	$	—	$	117	$	30	$	147

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

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:

	2012			2011			2010
(millions)
Balance at January 1,	$	(28	)	$	14		$	(10	)
Total realized and unrealized gains (losses):
Included in earnings		(50	)		(45	)		51
Included in regulatory assets/liabilities		30			(42	)		24
Settlements		50			45			(51	)
Transfers out of Level 3		—			—			—
Balance at December 31,	$	2		$	(28	)	$	14

The gains and losses included in earnings in the Level 3 fair value category, including those attributable to the change in unrealized gains and losses relating to assets still held at the reporting date, were classified in electric fuel and other energy-related purchases expense in Virginia Power’s Consolidated Statements of Income for the years ended December 31, 2012, 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 years ended December 31, 2012, 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 Vir-

81

Combined Notes to Consolidated Financial Statements, Continued

ginia Power’s financial instruments that are not recorded at fair value, the carrying amounts and fair values are as follows:

At December 31,	2012				2011
	Carrying Amount		Estimated Fair  Value(1)		Carrying Amount		Estimated Fair  Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	16,841	$	19,898	$	16,264	$	18,936
Long-term debt, including securities due within one year—VIE(3)		860		864		890		892
Junior subordinated notes		1,373		1,430		1,719		1,786
Subsidiary preferred stock(4)		257		255		257		256
Virginia Power
Long-term debt, including securities due within one year(2)	$	6,669	$	8,270	$	6,862	$	8,281
Preferred stock(4)		257		255		257		256

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

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

(3) Includes amounts which represent the unamortized premium.

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

NOTE 7. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES

Dominion and Virginia Power are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as currency exchange and interest rate risks of their business operations. The Companies use derivative instruments to manage exposure to these risks, and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes. As discussed in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivatives are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings. See Note 6 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 December 31, 2012. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)		249		68
Basis(1)		786		534
Electricity (MWh):
Fixed price(1)		20,100,938		12,582,674
FTRs		46,851,683		—
Capacity (MW)		151,025		148,461
Liquids (gallons)(2)		164,682,000		145,698,000
Interest rate	$	1,500,000,000	$	2,250,000,000

(1) Includes options.

(2) Includes NGLs and oil.

For the years ended December 31, 2012, 2011 and 2010, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at December 31, 2012:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(28	)	$	(24	)		27 months
Electricity		68			17			36 months
Other		3			2			41 months
Interest rate		(165	)		(21	)		361 months
Total	$	(122	)	$	(26	)

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 resulted in the discontinuance of hedge accounting for certain cash flow hedges in 2010, 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 was determined that the 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

82

from AOCI to earnings of $110 million ($67 million after-tax) for 2010. The reclassification of gains from AOCI to earnings was partially offset by subsequent changes in fair value for these contracts of $37 million ($23 million after-tax) for 2010.

Fair Value and Gains and Losses on Derivative Instruments

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

At December 31, 2012	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
ASSETS
Current Assets
Commodity	$	103	$	379	$	482
Interest rate		36		—		36
Total current derivative assets		139		379		518
Noncurrent Assets
Commodity		130		123		253
Interest rate		57		—		57
Total noncurrent derivative assets(1)		187		123		310
Total derivative assets	$	326	$	502	$	828
LIABILITIES
Current Liabilities
Commodity	$	103	$	341	$	444
Interest rate		66		—		66
Total current derivative liabilities		169		341		510
Noncurrent Liabilities
Commodity		58		93		151
Total noncurrent derivative liabilities(2)		58		93		151
Total derivative liabilities	$	227	$	434	$	661
At December 31, 2011
ASSETS
Current Assets
Commodity	$	176	$	495	$	671
Interest rate		34		—		34
Total current derivative assets		210		495		705
Noncurrent Assets
Commodity		198		96		294
Interest rate		71		—		71
Total noncurrent derivative assets(1)		269		96		365
Total derivative assets	$	479	$	591	$	1,070
LIABILITIES
Current Liabilities
Commodity	$	162	$	530	$	692
Interest rate		222		37		259
Total current derivative liabilities		384		567		951
Noncurrent Liabilities
Commodity		118		78		196
Interest rate		—		10		10
Total noncurrent derivative liabilities(2)		118		88		206
Total derivative liabilities	$	502	$	655	$	1,157

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

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

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 Year Ended December 31, 2012	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)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	188
Purchased gas					(75	)
Electric fuel and other energy-related purchases					(17	)
Total commodity	$	71		$	96		$	10
Interest rate(3)		(84	)		(2	)		(35	)
Total	$	(13	)	$	94		$	(25	)
Year Ended December 31, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	153
Purchased gas					(78	)
Electric fuel and other energy-related purchases					(2	)
Purchased electric capacity					1
Total commodity	$	137		$	74		$	(20	)
Interest rate(3)		(252	)		(8	)		(143	)
Total	$	(115	)	$	66		$	(163	)
Year Ended December 31, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	557
Purchased gas					(155	)
Electric fuel and other energy-related purchases					(8	)
Purchased electric capacity					3
Total commodity	$	139		$	397		$	(17	)
Interest rate(3)		(3	)		109			(27	)
Foreign currency(4)		—			1			(2	)
Total	$	136		$	507		$	(46	)

(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.

83

Combined Notes to Consolidated Financial Statements, Continued

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2012			2011			2010
(millions)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue	$	168		$	111		$	67
Purchased gas		(14	)		(35	)		(41	)
Electric fuel and other energy-related purchases		(40	)		(45	)		51
Interest rate(2)		17			(5	)		(37	)
Total	$	131		$	26		$	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 at December 31, 2012. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price		16		—
Basis		8		—
Electricity (MWh):
Fixed price		709,600		—
FTRs		43,570,739		—
Capacity (MW)		107,000		93,800
Interest rate	$	500,000,000	$	250,000,000

For the years ended December 31, 2012, 2011 and 2010, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to the time value of options and changes in the differences between spot prices and forward prices.

Fair Value and Gains and Losses on Derivative Instruments

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

At December 31, 2012	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
ASSETS
Current Assets
Commodity	$	1	$	5	$	6
Total current derivative assets(1)		1		5		6
Total derivative assets	$	1	$	5	$	6
LIABILITIES
Current Liabilities
Commodity	$	5	$	3	$	8
Interest rate		25		—		25
Total current derivative liabilities		30		3		33
Noncurrent Liabilities
Commodity		1		—		1
Total noncurrent derivative liabilities(2)		1		—		1
Total derivative liabilities	$	31	$	3	$	34
At December 31, 2011
ASSETS
Current Assets
Commodity	$	—	$	2	$	2
Total current derivative assets(1)		—		2		2
Total derivative assets	$	—	$	2	$	2
LIABILITIES
Current Liabilities
Commodity	$	14	$	31	$	45
Interest rate		53		37		90
Total current derivative liabilities		67		68		135
Noncurrent Liabilities
Commodity		2		—		2
Interest rate		—		10		10
Total noncurrent derivative liabilities(2)		2		10		12
Total derivative liabilities	$	69	$	78	$	147

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

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

84

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 Year Ended December 31, 2012	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)
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(4	)
Total commodity	$	(2	)	$	(4	)	$	10
Interest rate(3)		(6	)		—			(35	)
Total	$	(8	)	$	(4	)	$	(25	)
Year Ended December 31, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Purchased electric capacity					1
Total commodity	$	(3	)	$	—		$	(20	)
Interest rate(3)		(6	)		1			(143	)
Total	$	(9	)	$	1		$	(163	)
Year Ended December 31, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Purchased electric capacity					4
Total commodity	$	(1	)	$	3		$	(17	)
Interest rate(3)		(1	)		9			(27	)
Foreign currency(4)		—			—			(2	)
Total	$	(2	)	$	12		$	(46	)

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

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

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

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

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2012			2011			2010
(millions)
Derivative Type and Location of Gains (Losses)
Commodity(2)	$	(50	)	$	(45	)	$	51
Interest rate(3)		—			(5	)		(3	)
Total	$	(50	)	$	(50	)	$	48

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

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

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

NOTE 8. EARNINGS PER SHARE

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

	2012		2011		2010
(millions, except EPS)
Net income attributable to Dominion	$	302	$	1,408	$	2,808
Average shares of common stock outstanding-Basic		572.9		573.1		588.9
Net effect of potentially dilutive securities(1)		1.0		1.5		1.2
Average shares of common stock outstanding-Diluted		573.9		574.6		590.1
Earnings Per Common Share-Basic	$	0.53	$	2.46	$	4.77
Earnings Per Common Share-Diluted	$	0.53	$	2.45	$	4.76

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

85

Combined Notes to Consolidated Financial Statements, Continued

There were no potentially dilutive securities excluded from the calculation of diluted EPS for the years ended December 31, 2012, 2011 and 2010.

NOTE 9. INVESTMENTS

DOMINION

Equity and Debt Securities

RABBI TRUST SECURITIES

Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled $95 million and $90 million at December 31, 2012 and 2011, respectively. Cost-method investments held in Dominion’s rabbi trusts totaled $14 million and $17 million at December 31, 2012 and 2011, 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)
2012
Marketable equity securities:
U.S.:
Large Cap	$	1,210	$	732	$	—		$	1,942
Other		40		13		—			53
Marketable debt securities:
Corporate debt instruments		295		30		—			325
U.S. Treasury securities and agency debentures		523		19		(2	)		540
State and municipal		248		26		—			274
Other		6		1		—			7
Cost method investments		117		—		—			117
Cash equivalents and other(2)		72		—		—			72
Total	$	2,511	$	821	$	(2	)(3)	$	3,330
2011
Marketable equity securities:
U.S.:
Large Cap	$	1,152	$	537	$	—		$	1,689
Other		36		10		—			46
Marketable debt securities:
Corporate debt instruments		314		19		(1	)		332
U.S. Treasury securities and agency debentures		437		20		(1	)		456
State and municipal		264		24		—			288
Other		23		1		—			24
Cost method investments		118		—		—			118
Cash equivalents and other(2)		46		—		—			46
Total	$	2,390	$	611	$	(2	)(3)	$	2,999

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

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

(3) The fair value of securities in an unrealized loss position was $195 million and $164 million at December 31, 2012 and 2011, respectively.

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at December 31, 2012 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	116
Due after one year through five years		304
Due after five years through ten years		357
Due after ten years		369
Total	$	1,146

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

Year Ended December 31,	2012		2011		2010
(millions)
Proceeds from sales	$	1,356	$	1,757	$	1,814	(1)
Realized gains(2)		98		79		111
Realized losses(2)		33		92		63

(1) Does not include $1 billion of proceeds reflected in Dominion’s Consolidated Statement of Cash Flows from the sale of temporary investments

86

consisting of time deposits and Treasury Bills, purchased following the sale of substantially all of Dominion’s Appalachian E&P operations.

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

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

Year Ended December 31,	2012			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	26		$	75		$	59
Losses recorded to decommissioning trust regulatory liability		(10	)		(24	)		(21	)
Losses recognized in other comprehensive income (before taxes)		(2	)		(3	)		(3	)
Net impairment losses recognized in earnings	$	14		$	48		$	35

(1) Amounts include other-than-temporary impairment losses for debt securities of $4 million, $6 million and $10 million at December 31, 2012, 2011 and 2010, respectively.

Equity Method Investments

Investments that Dominion accounts for under the equity method of accounting are as follows:

Company	Ownership%			Investment Balance				Description
As of December 31,				2012		2011
(millions)
Fowler I Holdings LLC		50	%	$	158	$	166	Wind-powered merchant generation facility
NedPower Mount Storm LLC		50	%		137		146	Wind-powered merchant generation facility
Elwood Energy LLC		50	%		117		108	Natural gas-fired merchant generation peaking facility
Iroquois Gas Transmission System, LP		24.72	%		102		104	Gas transmission system
Blue Racer Midstream LLC		50	%		39		—	Midstream gas and related services
Other(1)		various			5		29
Total				$	558	$	553

(1) Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018.

Dominion’s equity earnings on these investments totaled $25 million, $35 million and $42 million in 2012, 2011 and 2010, respectively. Dominion received distributions from these investments of $58 million, $55 million and $60 million in 2012, 2011, and 2010, respectively. As of December 31, 2012 and 2011, the carrying amount of Dominion’s investments exceeded Dominion’s share of underlying equity in net assets by approximately $30 million and $32 million, respectively. The differences relate to Dominion’s investments in wind projects and primarily reflect its capitalized interest during construction and the excess of its cash contributions over the book value of development assets contributed by Dominion’s partners for these projects. The differences are generally being amortized over the useful lives of the underlying assets.

BLUE RACER

In December 2012, Dominion formed a joint venture with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. The joint venture, Blue Racer, is an equal partner-

ship between Dominion and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital. In return for its December 2012 contribution of assets to the joint venture, Dominion received a 50% interest in Blue Racer and received $115 million in cash proceeds, resulting in a gain of $72 million ($43 million after-tax), net of transaction fees of $9 million, which is recorded in other operations and maintenance expense in Dominion’s Consolidated Statement of Income. The joint venture will leverage Dominion’s existing presence in the Utica region with significant additional new capacity designed to meet producer needs as the Utica Shale acreage is developed. Midstream services offered will include gathering, processing, fractionation, and NGL transportation and marketing. In addition to the assets already contributed, Dominion expects to contribute additional gathering assets, the Natrium extraction plant and related NGL Pipeline, and a DTI pipeline connecting East Ohio’s gathering system to Natrium.

VIRGINIA POWER

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

	Amortized Cost		Total Unrealized Gains(1)		Total Unrealized Losses(1)			Fair Value
(millions)
2012
Marketable equity securities:
U.S.:
Large Cap	$	481	$	298	$	—		$	779
Other		20		7		—			27
Marketable debt securities:
Corporate debt instruments		179		17		—			196
U.S. Treasury securities and agency debentures		231		4		(1	)		234
State and municipal		106		11		—			117
Other		1		—		—			1
Cost method investments		117		—		—			117
Cash equivalents and other(2)		44		—		—			44
Total	$	1,179	$	337	$	(1	)(3)	$	1,515
2011
Marketable equity securities:
U.S.:
Large Cap	$	460	$	218	$	—		$	678
Other		18		5		—			23
Marketable debt securities:
Corporate debt instruments		204		11		(1	)		214
U.S. Treasury securities and agency debentures		166		4		—			170
State and municipal		114		10		—			124
Other		16		1		(1	)		16
Cost method investments		118		—		—			118
Cash equivalents and other(2)		27		—		—			27
Total	$	1,123	$	249	$	(2	)(3)	$	1,370

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

87

Combined Notes to Consolidated Financial Statements, Continued

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

(3) The fair value of securities in an unrealized loss position was $104 million and $99 million at December 31, 2012 and 2011, respectively.

The fair value of Virginia Power’s debt securities at December 31, 2012, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	18
Due after one year through five years		156
Due after five years through ten years		217
Due after ten years		157
Total	$	548

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

Year Ended December 31,	2012		2011		2010
(millions)
Proceeds from sales	$	626	$	1,030	$	1,192
Realized gains(1)		42		34		52
Realized losses(1)		11		34		23

(1) Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2.

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

Year Ended December 31,	2012			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	11		$	29		$	25
Losses recorded to decommissioning trust regulatory liability		(10	)		(24	)		(21	)
Losses recorded in other comprehensive income (before taxes)		—			(1	)		(1	)
Net impairment losses recognized in earnings	$	1		$	4		$	3

(1) Amounts include other-than-temporary impairment losses for debt securities of $2 million, $4 million and $6 million at December 31, 2012, 2011 and 2010, respectively.

OTHER INVESTMENTS

Dominion and Virginia Power hold restricted cash and cash equivalent balances that primarily consist of money market fund investments held in trust for the purpose of funding certain qual-

ifying construction projects. At December 31, 2012 and 2011, Dominion had $37 million and $147 million, respectively, and Virginia Power had $10 million and $32 million, respectively, of restricted cash and cash equivalents. These balances are presented in Other Current Assets and Investments in the Consolidated Balance Sheets.

NOTE 10. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:

At December 31,	2012		2011
(millions)
Dominion
Utility:
Generation	$	13,707	$	11,793
Transmission		7,799		6,604
Distribution		11,071		10,401
Storage		2,137		2,060
Nuclear fuel		1,277		1,193
Gas gathering and processing		803		727
General and other		803		778
Other-including plant under construction		2,232		3,597
Total utility		39,829		37,153
Nonutility:
Merchant generation—nuclear		1,163		1,108
Merchant generation—other(1)		1,289		2,780
Nuclear fuel		775		847
Other-including plant under construction		1,265		1,102
Total nonutility		4,492		5,837
Total property, plant and equipment	$	44,321	$	42,990
Virginia Power
Utility:
Generation	$	13,707	$	11,793
Transmission		4,261		3,823
Distribution		8,701		8,231
Nuclear fuel		1,277		1,193
General and other		659		631
Other-including plant under construction		2,017		2,946
Total utility		30,622		28,617
Nonutility-other		9		9
Total property, plant and equipment	$	30,631	$	28,626

(1) Amount includes $957 million due to consolidation of a VIE.

88

Jointly-Owned Power Stations

Dominion’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2012 is as follows:

	Bath County Pumped Storage Station(1)			North Anna Units 1 and 2(1)			Clover Power Station(1)			Millstone Unit 3(2)
(millions, except percentages)
Ownership interest		60	%		88.4	%		50	%		93.5	%
Plant in service	$	1,024		$	2,392		$	568		$	993
Accumulated depreciation		(521	)		(1,072	)		(192	)		(236	)
Nuclear fuel		—			502			—			456
Accumulated amortization of nuclear fuel		—			(390	)		—			(272	)
Plant under construction		27			77			6			36

(1) Units jointly owned by Virginia Power.

(2) Unit jointly owned by Dominion.

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.

NOTE 11. GOODWILL AND INTANGIBLE ASSETS

Goodwill

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

	Dominion Generation		Dominion Energy			DVP		Corporate and Other		Total
(millions)
Balance at December 31, 2010(1)	$	1,338	$	712		$	1,091	$	—	$	3,141
Impairments/adjustments		—		—			—		—		—
Balance at December 31, 2011(1)	$	1,338	$	712		$	1,091	$	—	$	3,141
Asset disposition adjustment		—		(11	)		—		—		(11	)
Balance at December 31, 2012(1)	$	1,338	$	701		$	1,091	$	—	$	3,130

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

Other Intangible Assets

Dominion’s and Virginia Power’s other intangible assets are subject to amortization over their estimated useful lives. Dominion’s amortization expense for intangible assets was $82 million, $78 million and $107 million for 2012, 2011 and 2010, respectively. In 2012, Dominion acquired $102 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 19 years. Amortization expense for Virginia Power’s intangible assets was $22 million, $22 million and $26 million for 2012, 2011, and 2010, respectively. In 2012, Virginia Power acquired $53 million of intangible assets, primarily representing software, with an esti-

mated weighted-average amortization period of 31 years. The components of intangible assets are as follows:

At December 31,	2012				2011
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion
Software, licenses and other	$	859	$	327	$	888	$	278
Emissions allowances		5		1		80		53
Total	$	864	$	328	$	968	$	331
Virginia Power
Software, licenses and other	$	303	$	122	$	285	$	102
Total	$	303	$	122	$	285	$	102

Annual amortization expense for these intangible assets is estimated to be as follows:

	2013		2014		2015		2016		2017
(millions)
Dominion	$	65	$	56	$	43	$	37	$	25
Virginia Power	$	20	$	18	$	12	$	8	$	5

89

Combined Notes to Consolidated Financial Statements, Continued

NOTE 12. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities include the following:

At December 31,	2012		2011
(millions)
Dominion
Regulatory assets:
Unrecovered gas costs(1)	$	59	$	48
Deferred rate adjustment clause costs(2)		55		113
Virginia sales taxes(3)		37		32
Plant retirement(4)		25		27
Deferred cost of fuel used in electric generation(5)		—		249
Derivatives(6)		—		45
Other		27		27
Regulatory assets-current		203		541
Unrecognized pension and other postretirement benefit costs(7)		1,210		887
Deferred rate adjustment clause costs(2)		173		107
Income taxes recoverable through future rates(8)		140		121
Derivatives(6)		105		49
Other postretirement benefit costs(9)		21		26
Plant retirement(4)		11		25
Deferred cost of fuel used in electric generation(5)		—		122
Other		57		45
Regulatory assets-non-current		1,717		1,382
Total regulatory assets	$	1,920	$	1,923
Regulatory liabilities:
PIPP(10)	$	100	$	58
Provision for rate proceedings(11)		8		150
Other		28		35
Regulatory liabilities-current		136		243
Provision for future cost of removal and AROs(12)		985		901
Decommissioning trust(13)		501		399
Other		28		24
Regulatory liabilities-non-current		1,514		1,324
Total regulatory liabilities	$	1,650	$	1,567
Virginia Power
Regulatory assets:
Deferred rate adjustment clause costs(2)	$	51	$	113
Virginia sales taxes(3)		37		32
Plant retirement(4)		25		27
Deferred cost of fuel used in electric generation(5)		—		249
Derivatives(6)		—		45
Other		6		13
Regulatory assets-current		119		479
Deferred rate adjustment clause costs(2)		127		70
Income taxes recoverable through future rates(8)		110		100
Derivatives(6)		105		49
Plant retirement(4)		11		25
Deferred cost of fuel used in electric generation(5)		—		122
Other		43		33
Regulatory assets-non-current		396		399
Total regulatory assets	$	515	$	878
Regulatory liabilities:
Provision for rate proceedings(11)	$	7	$	150
Other		25		28
Regulatory liabilities-current		32		178
Provision for future cost of removal(12)		763		687
Decommissioning trust(13)		501		399
Other		21		9
Regulatory liabilities-non-current		1,285		1,095
Total regulatory liabilities	$	1,317	$	1,273

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

  (2) Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for more information.

  (3) Amounts to be recovered through an annual surcharge to reimburse Virginia Power for incremental sales taxes being incurred due to the repeal of the public service company sales tax exemption in Virginia.

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

  (5) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power’s generation operations. See Note 13 for more information.

  (6) As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

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

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

  (9) Primarily reflects costs recognized in excess of amounts included in regulated rates charged by Dominion’s regulated gas operations before rates were updated to reflect a change in accounting method for other postretirement benefit costs.

(10) Under PIPP, eligible customers can receive energy assistance based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rider according to East Ohio tariff provisions. See Note 13 for more information regarding PIPP.

(11) Reflects a reserve associated with the Biennial Review Order. See Note 13 for more information.

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

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

At December 31, 2012, approximately $319 million of Dominion’s and $240 million of Virginia Power’s regulatory assets represented past expenditures on which they do not currently earn a return. These expenditures are expected to be recovered within the next two years.

NOTE 13. REGULATORY MATTERS

Regulatory Matters Involving Potential Loss Contingencies

As a result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, 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 regulatory process such that the Companies are able to esti-

90

mate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss does not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on Dominion’s or Virginia Power’s financial position, liquidity or results of operations. The following is a discussion of Dominion’s and Virginia Power’s material pending and recent regulatory matters.

FERC—Electric

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

Rates

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

In July 2008, Virginia Power filed an application with FERC requesting a revision to its revenue requirement to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 1.5% for four of the projects (including the Meadow Brook-to-Loudoun and Carson-to-Suffolk lines, which were completed in 2011) and an incentive of 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008, the incentives were included in the PJM Tariff, and billing for the incentives was made accordingly. In 2012, PJM canceled one of the eleven projects with an estimated cost of $7 million. The total cost for the other ten projects included in Virginia Power’s formula rate for 2013 is $852 million and the remaining projects were completed in 2012. Numerous parties sought rehearing of the FERC order in August 2008, and in May 2012 FERC denied

rehearing. In July 2012, the North Carolina Commission filed an appeal of the FERC orders granting the incentives with the Fourth Circuit Court of Appeals. Although Virginia Power cannot predict the outcome of the appeal, it is not expected to have a material effect on results of operations.

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

PJM

In November 2011, PJM issued a formal notification that it would recalculate certain ancillary service revenues that had previously been paid during 2009, 2010 and 2011. Also in November 2011, PJM requested FERC permission to suspend its rebilling and repayment obligations associated with the recalculation of such revenues and petitioned FERC to establish a proceeding to determine the appropriate recalculations for the revenues during this period. In December 2011, FERC permitted the suspension of rebilling and repayment by PJM, subject to the outcome of FERC’s proceedings to determine the appropriate revenue recalculation. In April 2012, FERC issued an Order Establishing Hearing and Settlement Judge Procedures to address the appropriate recalculation of the ancillary service credits PJM will be required to collect from Virginia Power. In August 2012, PJM filed a settlement on behalf of itself, Virginia Power and the PJM Market Monitor. In November 2012, FERC approved the settlement resolving all issues in the proceeding. As of September 30, 2012, Virginia Power had accrued a liability of $33 million, and in January 2013, Virginia Power paid PJM approximately $33 million, resolving the matter.

Other Regulatory Matters

Electric Regulation in Virginia

The enactment of the Regulation Act in 2007 significantly changed electric service regulation in Virginia by instituting a modified cost-of-service rate model. With respect to most classes of customers, the Regulation Act ended Virginia’s planned transition to retail competition for its electric supply service.

91

Combined Notes to Consolidated Financial Statements, Continued

The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It provides for enhanced returns on capital expenditures on specific new generation projects, including but not limited to combined cycle gas generation, nuclear generation, clean coal/carbon capture compatible generation, and renewable generation projects. The Regulation Act also continues statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. Legislation was enacted in February 2013 that amends the Regulation Act prospectively. See Future Issues and Other Matters in Item 7. MD&A for a discussion of this legislation.

If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.

2011 Biennial Review

Pursuant to the Regulation Act and the Virginia Settlement Approval Order, in March 2011, Virginia Power submitted its base rate filing and accompanying schedules in support of the first biennial review of its base rates, terms and conditions, as well as of its earnings for the 2009 and 2010 test period. The biennial review included a determination of whether Virginia Power’s earnings for the 2009 and 2010 combined test years were within 50 basis points of the authorized ROE of 11.9% established in the Virginia Settlement Approval Order, as well as authorization of an ROE which will be applicable to base rates and rate adjustment clauses and which will be used to measure base rate earnings during the 2013 biennial review proceeding. As a result of the Virginia Settlement Approval Order and the Regulation Act, Virginia Power’s base rates are not subject to change based on the 2011 biennial review. In November 2011, the Virginia Commission issued the Biennial Review Order.

In the Biennial Review Order, the Virginia Commission declined to award a performance incentive for generating plant performance, customer service or operating efficiency in connection with the 2009-2010 biennial review. Instead, in March 2012, the Virginia Commission issued an order initiating a rulemaking proceeding to develop specific performance metrics and nationally recognized standards for determining positive or negative performance incentives for electric utilities. Such incentive criteria would be applied in future biennial review proceedings.

In September 2012, the Virginia Commission issued an Order for Notice and Hearing in the separate rulemaking proceeding to develop specific performance standards based on nationally recognized standards for the Virginia Commission’s consideration in determining positive or negative performance incentives for electric utilities. The Virginia Commission modified the proposed rules and regulations for performance incentives filed by the Staff of the Virginia Commission, allowed for further comments by November 2012 on the proposed rules and regulations as modified, and held a public hearing in November 2012. In January 2013, the Virginia Commission issued its order adopting revised performance incentive rules and regulations effective February 1, 2013.

Base ROE

The Virginia Commission determined that Virginia Power’s new authorized ROE is 10.9%, inclusive of a performance incentive of 50 basis points for meeting certain RPS targets. As discussed below, this ROE will serve as the ROE against which Virginia Power’s earned return will be compared for the test periods in the 2013 biennial review proceeding. The Virginia Commission ordered that the 50 basis point RPS performance incentive will not be included in the ROE applicable to any rate adjustment clauses.

In December 2011, Virginia Power filed a petition with the Virginia Commission seeking rehearing or reconsideration of the Biennial Review Order, to confirm the effective date of the newly authorized 10.9% base ROE. Virginia Power’s petition requested the Virginia Commission to confirm that the 10.9% ROE authorized in the Biennial Review Order would apply prospectively, effective following the date of the Biennial Review Order on November 30, 2011, and that Virginia Power’s previously-approved 11.9% base ROE authorized in the Virginia Settlement Approval Order would be used to measure base rate earnings for the period January 1, 2011 through November 30, 2011. In March 2012, the Virginia Commission issued an order denying Virginia Power’s petition seeking rehearing or reconsideration. Contrary to Virginia Power’s position, the Virginia Commission ruled that the new 10.9% ROE will be used to measure earnings for the entire 2011-2012 test period in the next biennial review in 2013, which is expected to be filed in March 2013.

Also in March 2012, Virginia Power filed Petitions for Appeal with the Supreme Court of Virginia regarding the Biennial Review Order and the March 2012 Order. In May 2012, the Supreme Court of Virginia granted review of Virginia Power’s appeals from the Biennial Review Order and the March 2012 Order denying Virginia Power’s petition seeking rehearing or reconsideration, and heard oral argument on both appeals in September 2012. In November 2012, the Supreme Court of Virginia affirmed the Biennial Review Order and the March 2012 Order denying Virginia Power’s petition seeking rehearing or reconsideration.

ROE Applicable to Riders C1, C2, R, and S

Effective December 1, 2011, the ROE applicable to Riders C1 and C2 is 10.4%. For Riders R and S, effective December 1, 2011, the ROE is 11.4%, inclusive of a statutory enhancement of 100 basis points.

Earned Return for 2009 and 2010

The Virginia Commission determined that Virginia Power earned an ROE of approximately 13.3% during the 2009 and 2010 combined test years, which exceeded the authorized ROE earnings band of 11.4% to 12.4% established in the Virginia Settlement Approval Order. Based on the determination that Virginia Power had excess earnings, the Virginia Commission ordered Virginia Power to refund 60% of earnings above the upper end of the authorized ROE earnings band, or approximately $78 million, to its customers, which was provided in the form of credits to customers’ bills amortized over a six-month period during 2012. A charge for the refund was recognized in operating revenues in the 2011 Consolidated Statement of Income. The actual

92

aggregate refund amount totaled approximately $81 million, taking into account refunds to be paid to certain non-jurisdictional customers pursuant to their customer contracts.

Base Rates and Existing Riders T, C1, and C2

As a result of the Virginia Commission’s determination that credits will be applied to customers’ bills, the Virginia Commission, as required by the Regulation Act, directed Virginia Power to combine its existing Riders T, C1, and C2 with Virginia Power’s base costs, revenues and investments, and to file revised tariffs reflecting such combination pursuant to the Biennial Review Order. These Riders will thereafter be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings.

In April 2012, the Virginia Commission held that Riders C1 and C2 are now to be combined in Virginia Power’s base rates and are to be considered as part of its future biennial reviews. The Virginia Commission rejected Virginia Power’s requests to identify and separately track the revenues for these existing riders in base rates, and to preserve deferral accounting for these revenues in base rates, stating that such deferral accounting ceased December 1, 2011 for existing Riders C1 and C2.

In August 2012, the Virginia Commission confirmed that existing Rider T had been combined in base rates, and ruled that transmission costs would continue to be tracked separately to permit deferral accounting and dollar-for-dollar recovery of costs through Rider T and through Rider T1, a new increment/decrement rate adjustment clause to recover the difference in the revenue requirement for rate year costs and the revenues collected under Rider T.

Earnings Test Adjustments

The Virginia Commission ruled on numerous contested proposals to adjust Virginia Power’s earnings for the 2009 and 2010 combined test periods. Among other adjustments, the Virginia Commission approved Virginia Power’s ratemaking treatment of fuel inventories held by its wholly-owned subsidiaries. As a result of this finding, Virginia Power included in rate base approximately $188 million in fuel inventory costs for 2010. The Virginia Commission also adopted Virginia Power’s treatment that includes, for regulatory earnings purposes, its AIP and LTIP expenses up to a 100% payout ratio. The Virginia Commission excluded from expense approximately $21 million in incentive plan costs that exceeded a payout ratio of 100%, allowing a net recovery of approximately $95 million of incentive compensation expense for the biennial review period. The Virginia Commission denied Virginia Power’s ratemaking treatment that expensed the entire cost of its 2010 voluntary separation plan in 2010, ruling instead to amortize the cost through the end of 2011. This matched the costs of the plan with the period of realization of savings, which reduced 2010 operating costs (and in turn, increased 2011 operating costs) by approximately $103 million for purposes of the earnings test. Other than influencing the amount earned above the authorized ROE earnings band, the earnings test adjustments above did not have an impact to the Consolidated Financial Statements.

In addition, the Virginia Commission required Virginia Power to recognize a gain, for purposes of the earnings test, of approximately $44 million on the settlement of certain interest

rate hedging contracts in 2010, as opposed to amortizing the gains over the forecasted term of planned debt instruments that were not issued. Virginia Power determined that it was no longer probable that these derivative gains would be included in future base rates as the Virginia Commission would not allow the amortization of these amounts in future periods. As a result, Virginia Power removed approximately $50 million in December 2011 from regulatory liabilities and recognized the deferred derivative settlement gains in interest and related charges in the Consolidated Statements of Income.

Virginia Fuel Expenses

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

Generation Riders R and S

In connection with the Bear Garden and Virginia City Hybrid Energy Center projects, in March 2011, the Virginia Commission approved annual updates for Riders R and S with revenue requirements of $78 million and $199 million, respectively, for the April 1, 2011 to March 31, 2012 rate year, utilizing the 12.3% placeholder ROE (inclusive of a 100 basis point statutory enhancement) pending the Virginia Commission’s ROE determination in the 2011 biennial review.

In March 2012, the Virginia Commission approved annual updates for Riders R and S for the April 1, 2012 to March 31, 2013 rate year, utilizing an 11.4% ROE (inclusive of a 100 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order. The Virginia Commission’s approvals authorized an approximately $74 million revenue requirement for Rider R, and an approximately $226 million revenue requirement for Rider S, comprised of approximately $52 million for the pre-commercial operation period and approximately $174 million for the commercial operation period.

In June 2012, Virginia Power requested Virginia Commission approval of its annual updates for Riders R and S for the next two consecutive rate years, utilizing an 11.4% ROE (inclusive of a 100 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order and subject to true-up based on changes in the authorized ROE in future biennial review proceedings. For Rider R, Virginia Power proposed an approximately $81 million revenue requirement for the rate year beginning April 1, 2013 and an approximately $75 million revenue requirement for the rate year beginning April 1, 2014. For Rider S, an approximately $249 million revenue requirement was proposed for the rate year beginning April 1, 2013 and an approximately $229 million revenue requirement was proposed for the rate year beginning April 1, 2014. Virginia Power has agreed to certain adjustments supported by Virginia Commission Staff reducing the Rider R revenue requirements to approximately $78 million for the rate year beginning April 1, 2013, and approximately $72 million for the rate year beginning April 1, 2014. In February 2013, the Virginia Commission approved these cost recovery periods and amounts for Rider R, as well as a multi-year approach in which Virginia Power would file its next

93

Combined Notes to Consolidated Financial Statements, Continued

update filing for Rider R in 2014. In January 2013, Virginia Power filed a proposed stipulation agreement reached with the Virginia Commission Staff supporting a revised revenue requirement for Rider S of approximately $248 million for the rate year beginning April 1, 2013. Virginia Power and the Staff of the Virginia Commission also agreed that Virginia Power would file a Rider S case in 2013 instead of a multi-year approach. The Rider S update proceeding is pending. Construction of the Virginia City Hybrid Energy Center was completed and the facility commenced commercial operations in July 2012.

DSM Riders C1A and C2A

In April 2012, the Virginia Commission approved a revenue requirement of $5 million for Rider C1A and $17 million for Rider C2A. This approval incorporated four new energy efficiency DSM programs as a bundle for residential customers for a five-year period starting June 1, 2012, subject to a total $90 million cost cap. The Virginia Commission also approved two new energy efficiency DSM programs as a bundle for commercial customers for the same five-year period, subject to a total $45 million cost cap, as well as a new peak-shaving DSM program for commercial customers for the same five-year period, subject to an approximately $14 million cost cap.

In August 2012, Virginia Power requested extension of two DSM programs (the Residential Air Conditioner Cycling Program and the Residential Low Income Program) by five years and two years, respectively, beyond their current April 30, 2013 termination date, as well as approval of a process whereby the Staff could administratively approve limited modifications to the designs of previously approved DSM programs. Virginia Power’s proposed revenue requirements for Riders C1A and C2A for the May 1, 2013 to April 30, 2014 rate year are $4 million and $23 million, respectively. This case is pending.

Transmission Riders T and T1

In May 2011, Virginia Power filed its annual update to Rider T with the Virginia Commission. The proposed $481 million annual revenue requirement, effective September 1, 2011, represented an increase of approximately $144 million over the revenue requirement associated with the Rider T customer rates previously in effect. In July 2011, the Virginia Commission issued an order approving a revenue requirement of $466 million for the September 1, 2011 to August 31, 2012 rate year. As discussed above, previously implemented Rider T will be considered part of Virginia Power’s base costs, revenues and investments for purposes of future biennial review proceedings. The Virginia Commission has initiated a proceeding to address further implementation of this directive.

In May 2012, Virginia Power filed Rider T1 with the Virginia Commission to recover costs of transmission service and demand response programs for the September 1, 2012 to August 31, 2013 rate year. The proposed Rider T1 reduction of approximately $100 million produces a total annual revenue requirement of approximately $373 million when netted with the revenue requirement of approximately $473 million associated with the Rider T customer rates currently in effect, and now combined in Virginia Power’s base rates. Virginia Power’s filing stated that Rider T costs combined in base rates should be identified and separately tracked, with the continuation of deferral accounting and dollar-for-dollar recovery for these costs. Virginia Power’s

proposed revenue requirement was supported by the Staff of the Virginia Commission, although the Staff concurrently proposed an alternative methodology for the Rider T1 revenue requirement which would represent an increase of approximately $18 million from the current Rider T customer rates. The Staff’s alternative methodology would have precluded deferral accounting and dollar-for-dollar recovery for Rider T in future periods.

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

Generation Rider W

In May 2011, Virginia Power requested approval from the Virginia Commission to construct and operate Warren County, as well as approval of Rider W. In February 2012, the Virginia Commission approved Certificates of Public Convenience and Necessity for Warren County and related transmission facilities. The Virginia Commission also approved a revenue requirement of $34 million for the April 1, 2012 to March 31, 2013 rate year, reflecting an ROE of 11.4%, inclusive of a statutory enhancement of 100 basis points for Rider W, consistent with the Biennial Review Order. In addition, the Virginia Commission approved an ROE enhancement of 100 basis points for Rider W for a period of 10 years following commercial operations. The facility is expected to start commercial operations in late 2014.

In June 2012, Virginia Power requested Virginia Commission approval of its annual update for Rider W for the April 1, 2013 to March 31, 2014 rate year. Virginia Power proposed an approximately $86 million revenue requirement, utilizing an 11.4% ROE (inclusive of a 100 basis point statutory enhancement) also consistent with the base ROE authorized in the Biennial Review Order. In December, 2012, Virginia Power filed a proposed partial stipulation agreement reached with the Virginia Commission Staff supporting a revised revenue requirement for Rider W of approximately $83 million for the rate year commencing April 1, 2013. In February 2013, the Virginia Commission approved this revised revenue requirement.

Generation Rider B

In June 2011, Virginia Power filed applications with the Virginia Commission seeking regulatory approval to convert three of its coal-fired power stations to biomass. The applications included a request for approval of Rider B. To qualify for federal production tax credits associated with renewable energy generation, the power stations must commence operation as biomass generation facilities by December 31, 2013. Virginia Power requested Virginia Commission approval of the biomass conversions on a schedule that will enable qualification for these tax credits.

In March 2012, the Virginia Commission approved the conversion of the Altavista, Hopewell, and Southampton power stations to biomass. These conversions will increase Dominion’s

94

renewable generation by more than 150 MW and are expected to be completed by the end of 2013.

As part of its approval, the Virginia Commission also approved Rider B. The approved revenue requirement for Rider B is approximately $6 million for the April 1, 2012 to March 31, 2013 rate year, utilizing a 12.4% ROE (inclusive of a 200 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order. The renewable generating unit statutory enhancement of 200 basis points will apply during construction and the first five years of the service lives of the converted facilities.

In June 2012, Virginia Power requested Virginia Commission approval of its annual update for Rider B for the April 1, 2013 to March 31, 2014 rate year. Virginia Power proposed an approximately $12 million revenue requirement, utilizing a 12.4% ROE (inclusive of a 200 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order. In January 2013, Virginia Power filed a proposed stipulation agreement reached with the Virginia Commission Staff supporting approval of a revenue requirement for the pre-commercial operations date period and the post-commercial operations date period, resulting in an average recovery amount of approximately $12 million for the rate year commencing April 1, 2013. This case is pending.

Brunswick County Power Station and Generation Rider BW

In November 2012, Virginia Power requested approval from the Virginia Commission to construct and operate Brunswick County. The application included a request for approval of associated transmission facilities and Rider BW. Virginia Power’s proposed revenue requirement for Rider BW is approximately $45 million for the September 1, 2013 to August 31, 2014 rate year, reflecting an ROE of 11.4%, inclusive of a statutory enhancement of 100 basis points for Rider BW, consistent with the Biennial Review Order. Virginia Power requested an ROE enhancement of 100 basis points for Rider BW for a period of 15 years following commercial operations. The facility is expected to begin commercial operations in spring 2016. This case is pending.

Bremo Power Station

In August 2012, Virginia Power requested approval from the Virginia Commission of an amended and reissued Certificate of Public Convenience and Necessity that would allow Virginia Power to convert Bremo Units 3 and 4 from coal to natural gas as their fuel source. The proposed conversion would preserve 227 MW (net) of existing capacity and is expected to be complete in 2014. Cost recovery would occur through base rates, and not through a rate adjustment clause. This case is pending.

Solar Distributed Generation Demonstration Program

In October 2011, Virginia Power filed with the Virginia Commission an application to conduct a solar distributed generation demonstration program, consisting of up to a combined 30 MW of Company-owned solar distributed generation facilities to be located at selected commercial, industrial and community locations throughout its Virginia service territory. Virginia Power proposed to construct and operate the Company-owned facilities in two phases, with Phase I (up to 10 MW) from the date of approval through the end of 2013 and Phase II (up to 20 MW)

from the beginning of 2014 to the end of 2015. Virginia Power did not seek a rate adjustment clause for Phase I facilities with this filing; Phase I costs will be recovered as part of base rates in a future biennial review. Virginia Power indicated that it may seek a rate adjustment clause at a future time for Phase II costs.

In November 2012, the Virginia Commission approved the voluntary solar distributed generation demonstration program for Company-owned solar distributed generation facilities subject to a total cost cap of $80 million (including capital, financing, and operation and maintenance costs) which can be increased subject to future application based upon program experience, results, and data.

In May 2012, Virginia Power filed with the Virginia Commission a petition to implement a special tariff for a combined 3 MW of customer-owned solar distributed generation facilities. Under the proposed tariff, Rate Schedule SP, Virginia Power would purchase 100% of the energy output from these facilities, including all environmental attributes and associated renewable energy credits, at a fixed price of $0.15 per kWh for five years. As proposed, the costs of the purchases under Rate Schedule SP would not be recovered from all customers. Following comments, the Virginia Commission issued an order in November 2012 setting this matter for public hearing in February 2013. This case is pending.

Electric Transmission Projects

Portions of the Mt. Storm-to-Doubs line and certain associated facilities are approaching the end of their expected service lives and require replacement with new facilities to maintain reliable service. Virginia Power owns, and has been designated by PJM to rebuild, 96 miles of the line in West Virginia and Virginia, and The Potomac Edison Company owns, and has been designated by PJM to rebuild, the remaining three miles of the line in Maryland. In September 2011, the Virginia Commission approved Virginia Power’s application to rebuild its portion of the Mt. Storm-to-Doubs line. The approval of the West Virginia Commission was not required. Subject to applicable state and federal regulatory approvals, Virginia Power’s portion of the rebuild project is expected to be completed by June 2015.

In June 2010, the Virginia Commission authorized the construction of the Hayes-to-Yorktown line along the proposed eight-mile route utilizing existing easements and property previously acquired for the transmission line right-of-way. The Hayes-to-Yorktown line was placed in service in December 2012.

In July 2010, the Virginia Commission authorized Virginia Power to construct the Radnor Heights Project. The Virginia Commission stated that these lines and substation must be constructed and in service by June 30, 2012, and that Virginia Power could apply to extend this date for good cause shown. In October 2012, the Virginia Commission issued an order extending this construction and the in-service date to July 31, 2013.

In January 2012, the Virginia Commission authorized the replacement at higher voltage of approximately 43 miles of existing transmission lines between the Dooms and Bremo substations. The Dooms-to-Bremo line is expected to be completed by May 2014.

In December 2011, Virginia Power submitted an application to the Virginia Commission for approval of the Waxpool-Brambleton-BECO line. This project is required to provide requested service to

95

Combined Notes to Consolidated Financial Statements, Continued

a new data center campus in Loudoun County, Virginia. In December 2012, PJM authorized the Waxpool-Brambleton-BECO line as part of the 2012 RTEP and the Virginia Commission authorized construction of the line. In January 2013, a notice of appeal was filed with the Supreme Court of Virginia by a private party regarding the December 2012 Order. Subject to the receipt of applicable state and federal regulatory approvals, the Waxpool-Brambleton-BECO line is expected to be completed by November 2013.

In June 2012, Virginia Power requested Virginia Commission approval of the Surry-to-Skiffes Creek-to-Whealton lines. Subject to the receipt of applicable state and federal regulatory approvals, the Surry-to-Skiffes Creek-to-Whealton lines are expected to be completed by May 2015. Virginia Power also presented for the Virginia Commission’s consideration an approximately 37 mile alternate route for the 500 kV line from Virginia Power’s existing Chickahominy Substation to the proposed Skiffes Creek Switching Station.

In August 2012, Virginia Power requested Virginia Commission approval of the Harrisonburg-to-Endless Caverns line. In December 2012, the Virginia Commission authorized construction of the new line. Subject to the receipt of applicable state and federal regulatory approvals, the Harrisonburg-to-Endless Caverns line is expected to be completed by May 2015.

In November 2012, Virginia Power submitted an application to the Virginia Commission for approval to rebuild the Dooms-to-Lexington line in Virginia. Portions of the Dooms-to-Lexington line and certain associated facilities are approaching the end of their expected service lives and require replacement with new facilities to maintain reliable service. Virginia Power owns and has been designated by PJM as part of the 2012 RTEP to rebuild the 39 mile line in Rockbridge and Augusta Counties, Virginia. Subject to applicable state and federal regulatory approvals, the rebuild project is expected to be completed by May 2016.

North Anna Power Station

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. However, Virginia Power has not yet committed to building a new nuclear unit at North Anna and continues to evaluate its options regarding a new nuclear unit.

If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power has applied for and continues to pursue the COL from the NRC. Based on the current NRC schedule, the COL is expected no earlier than late 2015. Virginia Power also continues to pursue engineering and preliminary site development work, in addition to holding an Early Site Permit. In December 2011, Virginia Power acquired ODEC’s interest in the project, thereby terminating ODEC’s involvement in the development of a potential third unit at North Anna. In January 2013, the NRC approved the transfer of ODEC’s interest in the Early Site Permit to Virginia Power.

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. In April 2011, BREDL’s then last remaining contention was dismissed by the ASLB, and following a decision by the NRC in June 2012, subsequently resulted in termination of the contested portion of the proceed-

ing. 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, with the consent of BREDL and the NRC staff to hold any ruling on this proposed contention in abeyance until Virginia Power completes an assessment of this earthquake. The NRC’s June 2012 decision referred this new proposed contention to the ASLB to consider whether the contested portion of the proceeding should be reopened. In July 2012, the ASLB granted BREDL a period of 60 days to submit a motion to reopen the proceeding from the time Virginia Power informs the NRC and parties that its seismic assessment is complete.

In addition, in June 2012, BREDL filed a petition with the NRC seeking to suspend the COL proceeding based on a June 2012 ruling of the U.S. Court of Appeals for the District of Columbia Circuit reversing and remanding a 2010 NRC rulemaking that generically assessed the environmental impacts of spent fuel storage. Virginia Power opposed the petition. In July 2012, BREDL filed a motion with the NRC to reopen the contested portion of the COL proceeding to admit a contention pertaining to the same subject. Substantially identical suspension petitions and contentions were filed by various intervenor groups in other licensing proceedings pending before the NRC. In August 2012, the NRC issued a memorandum and order applicable to all pending licensing proceedings, including the North Anna COL proceeding. The NRC indicated that final licenses would not be issued until the issues raised in the court’s decision had been addressed. The NRC indicated that this determination extends only to final license issuance and that all licensing reviews and proceedings should continue to move forward. The NRC also directed that pending contentions on the topic be held in abeyance pending further NRC order. The NRC’s August 2012 decision is not expected to affect the schedule for issuance of the COL.

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. Virginia Power continues to pursue various environmental permits that would be needed to support future construction and operation of a third nuclear unit at North Anna.

North Carolina Regulation

In December 2011, the North Carolina Commission issued an order approving a settlement agreement among Virginia Power, the Public Staff of the North Carolina Commission and other interested parties in Virginia Power’s fuel case for its North Carolina service territory. The settlement agreement provided for a $36 million increase in Virginia Power’s fuel revenues for one year, effective January 1, 2012, including approximately $13 million in under recovery of fuel expenses for the previous fuel period.

In March 2012, Virginia Power filed an application with the North Carolina Commission to increase base non-fuel revenues by approximately $64 million, with January 1, 2013 as the proposed effective date for the permanent rate revision.

In August 2012, Virginia Power filed its annual fuel expense recovery application and testimony with the North Carolina Commission requesting a total annual fuel revenue decrease of approximately $27 million from the fuel and fuel-related costs currently in effect. Virginia Power’s filing also sought to implement a temporary voluntary rider, Rider A1, effective

96

November 1, 2012 to December 31, 2012, to reduce projected over-collection of fuel expense in the second half of 2012.

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

In December 2012, the North Carolina Commission approved a $36 million increase in Virginia Power’s annual non-fuel base revenues based on an authorized ROE of 10.2%, and a $14 million decrease in annual base fuel revenues for a combined total base revenue increase of $22 million. These rate changes became effective on January 1, 2013 and are being appealed to the North Carolina Supreme Court by multiple parties. In December 2012, Virginia Power established net regulatory assets of $17 million to be recovered over five to ten years in connection with these new rates.

Also, in December 2012, the North Carolina Commission approved a $17 million decrease in Virginia Power’s annual non-base fuel Experience Modification Factor revenues. The rate decrease is the result of the Commission’s approval of the Fuel-Related Stipulation of Settlement between the Public Staff and Virginia Power. The rate change was approved by the Commission after review of Virginia Power’s fuel expenses during the 12-month period ended June 30, 2012, and represents changes experienced by Virginia Power with respect to its reasonable costs of fuel and fuel component of purchased power.

Ohio Regulation

PIR Program

In March 2011, East Ohio filed a request with the Ohio Commission to accelerate the PIR program by nearly doubling its PIR spending to more than $200 million annually. East Ohio identified 1,450 miles of pipeline that need to be replaced, in addition to the pipeline originally identified in the PIR project scope. East Ohio plans to accelerate the pace of the program by investing more resources in its infrastructure in the near term, in an effort to promote ongoing public safety and reduce operating costs over the longer term. In August 2011, the Ohio Commission approved the stipulation by East Ohio, the Staff of the Ohio Commission and other interested parties 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 February 2012, East Ohio submitted an application with the Ohio Commission to adjust the cost recovery charge for costs associated with PIR investments for the six months ended December 31, 2011. The filing was made in accordance with changes to the PIR program approved by the Ohio Commission in August 2011 and effects a transition from a fiscal year ending June 30 to a calendar year for annual filings thereafter. The appli-

cation includes total gross plant investment for the six-month July 1-December 31, 2011 transition period of $73 million, cumulative gross plant investment of $362 million, and a revenue requirement of $47 million. A stipulation was submitted by East Ohio, the Staff of the Ohio Commission and the Ohio Consumers’ Counsel that supports the rates filed by East Ohio. The Ohio Commission issued an order approving the stipulation in April 2012.

In November 2012, East Ohio filed a notice to adjust the PIR Cost Recovery Charge for 2012 costs. East Ohio expects to file its application to adjust the PIR Recovery Charge in the first quarter of 2013.

PIPP Plus Program

Under the Ohio PIPP Plus program, eligible customers can receive energy assistance based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP plan payment amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. The PIPP Plus program sets the customer’s monthly payments at 6% of household income and provides for forgiveness credits to the customer’s balance when required payments are received in full by the due date. Such credits may result in the elimination of the customer’s arrearage balance over 24 months.

In July 2012, the Ohio Commission approved East Ohio’s annual update of the PIPP Rider, which reflects the refund of an over-recovery of accumulated arrearages of approximately $70 million over the next two years and recovery of projected deferred program costs of approximately $104 million for the 12-month period from April 2012 to March 2013.

UEX Rider

East Ohio files an annual UEX Rider with the Ohio Commission, pursuant to which it seeks recovery of the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar-for-dollar recovery of East Ohio’s actual write-offs of uncollectable amounts.

In July 2012, the Ohio Commission approved East Ohio’s annual update of the UEX Rider, which reflects the elimination of accumulated unrecovered bad debt expense of approximately $1 million as of March 31, 2012, and recovery of prospective bad debt expense projected to total approximately $23 million for the 12-month period from April 2012 to March 2013.

House Bill 95

Ohio enacted utility reform legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future. In December 2011, East Ohio filed an application requesting authority to implement a capital expenditure program under the new law, which, if approved, would enable East Ohio to defer as a regulatory asset carrying costs, depreciation and property tax associated with approximately $95 million in capital expenditures incurred between October

97

Combined Notes to Consolidated Financial Statements, Continued

2011 and December 2012 for assets placed in service but not yet reflected in rates. The Ohio Commission approved East Ohio’s application in December 2012.

In December 2012, East Ohio filed an application requesting authority to implement a capital expenditure program for 2013 capital expenditures totaling $93 million, subject to the provisions approved for the initial application. This case is pending.

Federal Regulation

FERC—Gas

FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate natural gas company subsidiaries, including DTI and Cove Point. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

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

NOTE 14. ASSET RETIREMENT OBLIGATIONS

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

The Companies have also identified, but not recognized, AROs related to retirement of Dominion’s LNG facility, Dominion’s gas storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in the Companies’ generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be

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

	Amount
(millions)
Dominion
AROs at December 31, 2010(1)	$	1,591
Obligations incurred during the period		16
Obligations settled during the period		(16	)
Revisions in estimated cash flows(2)		(277	)
Accretion		84
AROs at December 31, 2011(1)	$	1,398
Obligations incurred during the period		24
Obligations settled during the period		(13	)
Revisions in estimated cash flows(3)		242
Accretion		77
Other		(23	)
AROs at December 31, 2012(1)	$	1,705
Virginia Power
AROs at December 31, 2010(4)	$	672
Obligations incurred during the period		10
Obligations settled during the period		(3	)
Revisions in estimated cash flows(2)		(90	)
Accretion		36
AROs at December 31, 2011(4)	$	625
Obligations incurred during the period		18
Obligations settled during the period		(1	)
Revisions in estimated cash flows(5)		41
Accretion		34
Other		(12	)
AROs at December 31, 2012	$	705

(1) Includes $14 million, $15 million and $64 million reported in other current liabilities at December 31, 2010, 2011, and 2012, respectively.

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

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

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

(5) Primarily reflects the effect of higher anticipated nuclear decommissioning costs.

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

NOTE 15. VARIABLE INTEREST ENTITIES

The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant

98

variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.

Virginia Power has long-term power and capacity contracts with four non-utility generators with an aggregate summer generation capacity of approximately 870 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $1.1 billion as of December 31, 2012. Virginia Power paid $214 million, $211 million, and $213 million for electric capacity and $83 million, $125 million, and $164 million for electric energy to these entities for the years ended December 31, 2012, 2011 and 2010, respectively.

Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $328 million, $389 million, and $465 million for the years ended December 31, 2012, 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.

Dominion leases the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. Dominion makes annual lease payments of approximately $53 million. The lease expires in 2013 and, at that time, Dominion may renew the lease on terms mutually agreeable to Dominion and Juniper based on original project costs and current market conditions; purchase Fairless for approximately $923 million or sell Fairless, on behalf of Juniper, to an independent third party. If Fairless is sold and the proceeds from the sale are less than its original construction cost, Dominion would be required to make a payment to the lessor in an amount up to 70.75% of the original project costs adjusted for certain other costs as specified in the lease. The lease agreement does not contain any provisions that involve credit rating or stock price trigger events. Dominion expects to purchase Fairless when the lease expires in the third quarter of 2013.

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 subject to the business scope exception, Dominion was not required to evaluate whether Juniper was a VIE prior to October 2011.

Through September 30, 2011, Juniper held various power plant leases, including Fairless. In October 2011, the last lease other than Fairless expired and the related asset was sold by Juniper. With Fairless being its sole remaining asset, Juniper no longer qualified as a business as of October 2011, which required that Dominion determine whether Juniper 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 is not held by the equity holders, and Dominion, through its residual value guarantee discussed above, 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. The decisions related to the operations of Fairless are made by Dominion and as such, Dominion is considered the primary beneficiary.

Accordingly, Dominion consolidated Juniper in October 2011 and recorded, at fair value, approximately $957 million of property, plant and equipment, $896 million of debt and $61 million of noncontrolling interests. The debt is non-recourse to Dominion and is secured by Juniper’s assets. The annual lease payments made by Dominion to Juniper for Fairless are now eliminated in the Consolidated Statements of Income and are excluded from the lease commitments table in Note 22.

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 16. SHORT-TERM DEBT AND CREDIT AGREEMENTS

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.

99

Combined Notes to Consolidated Financial Statements, Continued

DOMINION

Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:

At December 31,	Facility Limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Capacity Available
(millions)
2012
Joint revolving credit facility(1)	$	3,000	$	2,412		$	—	$	588
Joint revolving credit facility(2)		500		—			26		474
Total	$	3,500	$	2,412	(3)	$	26	$	1,062
2011
Joint revolving credit facility(1)	$	3,000	$	1,814		$	—	$	1,186
Joint revolving credit facility(2)		500		—			36		464
Total	$	3,500	$	1,814	(3)	$	36	$	1,650

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

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

(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were 0.49% and 0.47% at December 31, 2012 and 2011, respectively.

VIRGINIA POWER

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.

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:

At December 31,	Facility Sub-limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Sub-Limit Capacity Available
(millions)
2012
Joint revolving credit facility(1)	$	1,000	$	992		$	—	$	8
Joint revolving credit facility(2)		250		—			2		248
Total	$	1,250	$	992	(3)	$	2	$	256
2011
Joint revolving credit facility(1)	$	1,000	$	894		$	—	$	106
Joint revolving credit facility(2)		250		—			15		235
Total	$	1,250	$	894	(3)	$	15	$	341

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

(2) Effective September 2012, the maturity date for $400 million of the $500 million in committed capacity of this credit facility was extended from September 2016 to September 2017. The remaining $100 million continues to have a maturity date of September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.

(3) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.47% and 0.46% at December 31, 2012 and 2011, respectively.

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

100

NOTE 17. LONG-TERM DEBT

At December 31,	2012 Weighted- average Coupon(1)			2012			2011
(millions, except percentages)
Virginia Electric and Power Company:
Unsecured Senior Notes:
4.75% to 8.625%, due 2012 to 2017		5.50	%	$	1,706		$	2,321
2.95% to 8.875%, due 2018 to 2038		5.83	%		4,008			3,558
Tax-Exempt Financings(2):
Variable rates, due 2016 to 2041		1.14	%		454			454
1.5% to 6.5%, due 2017 to 2040		3.65	%		508			533
Virginia Electric and Power Company total principal				$	6,676		$	6,866
Securities due within one year		4.88	%		(418	)		(616	)
Unamortized discount and premium, net					(7	)		(4	)
Virginia Electric and Power Company total long-term debt				$	6,251		$	6,246
Dominion Resources, Inc.:
Unsecured Senior Notes:
Variable rate, due 2013		0.41	%	$	400		$	—
1.4% to 7.195%, due 2012 to 2017		3.72	%		3,041			3,545
2.75% to 8.875%, due 2018 to 2042(3)		5.71	%		5,099			4,399
Unsecured Convertible Senior Notes, 2.125%, due 2023(4)					82			143
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031		7.85	%		268			268
Enhanced Junior Subordinated Notes:
7.5% and 8.375%, due 2064 and 2066		8.11	%		985			985
Variable rate, due 2066(5)		2.77	%		380			468
Unsecured Debentures and Senior Notes(6):
5.0% and 6.625%, due 2013 and 2014		5.06	%		622			622
6.8% and 6.875%, due 2026 and 2027		6.81	%		89			89
Dominion Energy, Inc.:
Secured Senior Notes:
5.03% to 5.78%, due 2013(7)		5.07	%		842			842
7.33%, due 2020(8)					145			159
Tax-Exempt Financings(9):
2.25% to 5.75%, due 2033 to 2042		3.34	%		284			284
Variable rate, due 2041		1.16	%		75			75
Virginia Electric and Power Company total principal (from above)					6,676			6,866
Dominion Resources, Inc. total principal				$	18,988		$	18,745
Fair value hedge valuation(10)					93			105
Securities due within one year(11)		4.53	%		(2,223	)		(1,479	)
Unamortized discount and premium, net					(7	)		23
Dominion Resources, Inc. total long-term debt				$	16,851		$	17,394

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2012.

(2) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. Certain variable rate tax-exempt financings are supported by a $120 million credit facility that terminates in September 2017.

(3) At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 and $600 million of Dominion’s 8.875% senior notes due 2019 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015 and January 2014, respectively.

(4) Convertible into a combination of cash and shares of Dominion’s common stock at any time when the closing price of common stock equals 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter. At the option of holders on December 15, 2013 or 2018, these securities are subject to redemption at 100% of the principal amount plus accrued interest. These senior notes have been callable by Dominion since December 15, 2011.

(5) In September 2011, the $500 million 6.3% September 2006 hybrids began bearing interest at the three-month LIBOR plus 2.3%, reset quarterly.

(6) Represents debt assumed by Dominion from the merger of its former CNG subsidiary.

(7) Juniper notes issued in 2004 and consolidated in October 2011 due to Dominion becoming the primary beneficiary of this VIE. This amount excludes $18 million and $48 million of unamortized premium in 2012 and 2011, respectively. The debt is non-recourse to Dominion and is secured by Juniper’s assets.

(8) Represents debt associated with Kincaid. The debt is non-recourse to Dominion and is secured by the facility’s assets ($552 million at December 31, 2012) and revenue. Dominion announced in the third quarter of 2012 that it was pursuing the sale of Kincaid. Dominion anticipates redeeming the notes as a condition to a sale of Kincaid.

(9) Includes debt issued by the Massachusetts Development Finance Agency on behalf of Brayton Point. Dominion announced in the third quarter of 2012 that it was pursuing the sale of Brayton Point.

(10) Represents the valuation of certain fair value hedges associated with Dominion’s fixed rate debt.

(11) Includes $23 million of net unamortized premium and fair value hedge valuation in 2012 and $4 million of net unamortized discount in 2011.

101

Combined Notes to Consolidated Financial Statements, Continued

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2012, were as follows:

	2013			2014			2015			2016			2017			Thereafter			Total
(millions, except percentages)
Virginia Power	$	418		$	17		$	211		$	476		$	679		$	4,875		$	6,676
Weighted-average Coupon		4.88	%		7.73	%		5.39	%		5.27	%		5.44	%		5.26	%
Dominion
Secured Senior Notes	$	852		$	15		$	18		$	20		$	22		$	60		$	987
Unsecured Senior Notes		1,090			1,065			960			1,351			1,303			9,278			15,047
Tax-Exempt Financings		—			—			—			19			75			1,227			1,321
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts		258			—			—			—			—			10			268
Enhanced Junior Subordinated Notes		—			—			—			—			—			1,365			1,365
Total	$	2,200		$	1,080		$	978		$	1,390		$	1,400		$	11,940		$	18,988
Weighted-average Coupon		4.53	%		3.99	%		4.50	%		4.27	%		4.60	%		5.54	%

Dominion’s and Virginia Power’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2012, there were no events of default under these covenants.

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

Convertible Securities

At December 31, 2012, Dominion had $82 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominion’s common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. At issuance, the notes were valued at a conversion rate of 27.173 shares of common stock per $1,000 principal amount of senior notes, which represented a conversion price of $36.80. The conversion rate is subject to adjustment without limitation 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 December 31, 2012, the conversion rate had been adjusted to 29.3863 shares, primarily due to individual dividend payments above the level paid at issuance. If the outstanding notes as of December 31, 2012 were all converted, it would result in the issuance of approximately 900 thousand additional shares. In December 2012, Dominion’s Board of Directors declared dividends payable March 20, 2013 of 56.25 cents per share of common stock which will increase the conversion rate to 29.5147 effective as of February 26, 2013.

The number of shares included in the denominator of the diluted EPS calculation is calculated as the net shares issuable for the reporting period based upon the average market price for the period. This results in an increase in the average shares outstanding used in the calculation of Dominion’s diluted EPS when the conversion price is lower than the average market price of Dominion’s common stock over the period, and results in no adjustment when the conversion price exceeds the average market price.

The senior notes are convertible by holders into a combination of cash and shares of Dominion’s common stock under any of the following circumstances:

(1) The closing price of Dominion’s common stock equals 120% of the applicable conversion price ($40.66 as of February 26,

2013) or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter;

(2) The senior notes are called for redemption by Dominion;

(3) The occurrence of specified corporate transactions; or

(4) The credit rating assigned to the senior notes by Moody’s is below Baa3 and by Standard & Poor’s is below BBB- or the ratings are discontinued for any reason.

The senior notes were eligible for conversion during 2012 since the closing price of Dominion’s common stock was equal to 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days of each quarter. During 2012, approximately $61 million of the contingent convertible senior notes were converted by holders. As of December 31, 2012, the closing price of Dominion’s common stock was equal to $40.84 per share or higher for at least 20 out of the last 30 consecutive trading days; therefore, the senior notes are eligible for conversion during the first quarter of 2013. Beginning in 2007, the notes have been eligible for contingent interest if the average trading price as defined in the indenture equals or exceeds 120% of the principal amount of the senior notes. Holders have the right to require Dominion to purchase these senior notes for cash at 100% of the principal amount plus accrued interest in December 2013 or 2018, or if Dominion undergoes certain fundamental changes. The senior notes have been callable by Dominion since December 15, 2011.

Junior Subordinated Notes Payable to Affiliated Trusts

In previous years, Dominion established several subsidiary capital trusts, each as a finance subsidiary of Dominion, which holds 100% of the voting interests. The trusts sold capital securities representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trusts. In exchange for the funds realized from the sale of the capital securities and common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trusts, Dominion issued various junior subordinated notes. The junior subordinated notes constitute 100% of each capital trust’s assets. Each trust must redeem its capital securities when their respective junior subordinated notes are repaid at maturity or if redeemed prior to maturity.

102

In November 2012, Dominion provided notice of redemption for its $258 million 7.83% unsecured junior subordinated debentures and all 250 thousand units of the $250 million 7.83% Dominion Resources Capital Trust I capital securities due December 1, 2027. At December 31, 2012, the debentures were included in securities due within one year in the Consolidated Balance Sheets. In January 2013, Dominion redeemed the securities at a price of $1,019.58 per capital security plus accrued and unpaid distributions.

The following table provides summary information about the capital securities and junior subordinated notes outstanding as of December 31, 2012:

Date Established	Capital Trusts	Units		Rate			Capital Securities Amount		Common Securities Amount
		(thousands)					(millions)
December 1997	Dominion Resources Capital Trust I(1)		250		7.83	%	$	250	$	7.7
January 2001	Dominion Resources Capital Trust III(2)		10		8.4			10		0.3

Junior subordinated notes/debentures held as assets by each capital trust were as follows:

(1) $258 million—Dominion Resources, Inc. 7.83% Debentures due 12/1/2027.

(2) $10 million—Dominion Resources, Inc. 8.4% Debentures due 1/15/2031.

Interest charges related to Dominion’s junior subordinated notes payable to affiliated trusts were $21 million for the years ended December 31, 2012, 2011 and 2010.

Distribution payments on the capital securities are considered to be fully and unconditionally guaranteed by Dominion. Each guarantee agreement only provides for the guarantee of distribution payments on the relevant capital securities to the extent that the trust has funds legally and immediately available to make distributions. The trust’s ability to pay amounts when they are due on the capital securities is dependent solely upon the payment of amounts by Dominion when they are due on the junior subordinated notes. Dominion may defer interest payments on the junior subordinated notes on one or more occasions for up to five consecutive years and the related trusts must also defer distributions. If the payment on the junior subordinated notes is deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments, during the deferral period. Also, during any deferral period, Dominion may not make any payments on, redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the junior subordinated notes.

Enhanced Junior Subordinated Notes

In June 2006 and September 2006, Dominion issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids will bear interest at 7.5% per year until June 30, 2016. Thereafter, they will bear interest at the three-month LIBOR plus 2.825%, reset quarterly. Beginning September 30, 2011, the September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly. Previously, interest was fixed at 6.3% per year.

In June 2009, Dominion issued $685 million (including $60 million related to the underwriter’s option to purchase additional

notes to cover over-allotments) of 8.375% June 2009 hybrids. The June 2009 hybrids are listed on the NYSE under the symbol DRU.

Dominion may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.

Dominion executed RCCs in connection with its issuance of all of the hybrids described above. Under the terms of the RCCs, Dominion covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. 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. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.

In both December 2011 and April 2010, Dominion purchased and canceled approximately $16 million of the September 2006 hybrids. In February 2012, Dominion launched a tender offer to purchase up to $150 million of additional September 2006 hybrids. In the first quarter of 2012, Dominion purchased and canceled approximately $86 million of the September 2006 hybrids primarily as a result of this tender offer, which expired in March 2012. In the second quarter of 2012, Dominion purchased and canceled approximately $2 million of the September 2006 hybrids. All purchases were conducted in compliance with the RCC.

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

NOTE 18. PREFERRED STOCK

Dominion is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2012 or 2011.

Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference, and had 2.59 million preferred shares issued and outstanding at December 31, 2012 and 2011. Upon involuntary liquidation,

103

Combined Notes to Consolidated Financial Statements, Continued

dissolution or winding-up of Virginia Power, each share would be entitled to receive $100 plus accrued cumulative dividends.

Holders of Virginia Power’s outstanding preferred stock are not entitled to voting rights except under certain provisions of the amended and restated articles of incorporation and related provisions of Virginia law restricting corporate action, upon default in dividends or in special statutory proceedings and as required by Virginia law (such as mergers, consolidations, sales of assets, dissolution and changes in voting rights or priorities of preferred stock).

Presented below are the series of Virginia Power preferred stock that were outstanding as of December 31, 2012:

Dividend	Issued and Outstanding Shares		Entitled Per Share Upon Liquidation
	(thousands)
$5.00		107	$	112.50
4.04		13		102.27
4.20		15		102.50
4.12		32		103.73
4.80		73		101.00
7.05		500		100.36	(1)
6.98		600		100.35	(2)
Flex Money Market Preferred 12/02, Series A		1,250		100.00	(3)
Total		2,590

(1) Through 7/31/2013; $100.00 commencing 8/1/2013.

(2) Through 8/31/2013; $100.00 commencing 9/1/2013.

(3) Dividend rate was 6.25% until 3/20/2011. Effective 3/20/11 the rate reset to 6.12% until 3/20/2014 after which the rate will be determined according to periodic auctions for periods established by Virginia Power at the time of the auction process.

NOTE 19. SHAREHOLDERS’ EQUITY

Issuance of Common Stock

DOMINION

Dominion maintains Dominion Direct^® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2012, Dominion began issuing new common shares for these direct stock purchase plans.

During 2012, Dominion issued approximately 6.4 million shares of common stock through various programs. Dominion received cash proceeds of $265 million from the issuance of 5.3 million of such shares through Dominion Direct, employee savings plans, and the exercise of employee stock options.

In January 2012, Dominion filed a new SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at the market program. Dominion entered into four separate Sales Agency Agreements to effect sales under the program. However, with the exception of issuing approximately $318 million in equity through employee savings plans, direct stock purchase and dividend reinvestment plans, converted securities and other employee and director benefit plans, Dominion did not issue common stock in 2012.

VIRGINIA POWER

In 2012 and 2011, Virginia Power did not issue any shares of its common stock to Dominion. In 2010, Virginia Power issued 33,013 shares of its common stock to Dominion for approximately $1 billion, for the purpose of retiring short-term demand note borrowings from Dominion.

Shares Reserved for Issuance

At December 31, 2012, Dominion had approximately 48 million shares reserved and available for issuance for Dominion Direct^®, employee stock awards, employee savings plans, director stock compensation plans and contingent convertible senior notes.

Repurchase of Common Stock

During 2011, Dominion repurchased approximately 13 million shares of common stock for approximately $601 million on the open market, at an average price of $46.37 per share. Dominion did not repurchase any shares in 2012 and does not plan to repurchase shares during 2013, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization.

Accumulated Other Comprehensive Income (Loss)

Presented in the table below is a summary of AOCI by component:

At December 31,	2012			2011
(millions)
Dominion
Net unrealized losses on derivatives-hedging activities, net of tax of $87 and $48	$	(122	)	$	(54	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(206) and $(154)		326			243
Net unrecognized pension and other postretirement benefit costs, net of tax of $745 and $568		(1,081	)		(799	)
Total AOCI	$	(877	)	$	(610	)
Virginia Power
Net unrealized losses on derivatives-hedging activities, net of tax of $3 and $2	$	(6	)	$	(3	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(19) and $(14)		31			22
Total AOCI	$	25		$	19

Stock-Based Awards

The 2005 Incentive Compensation Plan permits stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of both plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. At December 31, 2012, approximately 32 million shares were available for future grants under these plans.

Dominion measures and recognizes compensation expense relating to share-based payment transactions over the vesting

104

period based on the fair value of the equity or liability instruments issued. Dominion’s results for the years ended December 31, 2012, 2011 and 2010 include $25 million, $39 million, and $40 million, respectively, of compensation costs and $8 million, $13 million, and $15 million, respectively of income tax benefits related to Dominion’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. Excess tax benefits are classified as a financing cash flow. During the years ended December 31, 2012, 2011 and 2010, Dominion realized $10 million, $2 million, and $10 million, respectively, of excess tax benefits from the vesting of restricted stock awards and exercise of stock options.

STOCK OPTIONS

The following table provides a summary of changes in amounts of stock options outstanding as of and for the years ended December 31, 2012, 2011 and 2010. No options were granted under any plan in 2012, 2011 or 2010.

	Shares			Weighted - average Exercise Price		Weighted - average Remaining Contractual Life		Aggregated Intrinsic Value(1)
	(thousands)					(years)		(millions)
Outstanding and exercisable at December 31, 2009		3,822		$	31.25				29
Exercised		(1,983	)	$	30.81			$	22
Forfeited/expired		(29	)	$	29.84
Outstanding and exercisable at December 31, 2010		1,810		$	31.76			$	20
Exercised		(1,174	)	$	32.46			$	17
Forfeited/expired		(8	)	$	31.57
Outstanding and exercisable at December 31, 2011		628		$	30.81			$	14
Exercised		(622	)	$	30.79			$	13
Forfeited/expired		(6	)	$	32.26
Outstanding and exercisable at December 31, 2012		—		$	—		—	$	—

(1) Intrinsic value represents the difference between the exercise price of the option and the market value of Dominion’s stock.

Dominion issues new shares to satisfy stock option exercises. Dominion received cash proceeds from the exercise of stock options of approximately $19 million, $38 million, and $63 million in the years ended December 31, 2012, 2011 and 2010, respectively.

RESTRICTED STOCK

Restricted stock grants are made to officers under Dominion’s LTIP and may also be granted to certain key contributors from time to time. The fair value of Dominion’s restricted stock awards is equal to the market price of Dominion’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2012, 2011 and 2010:

	Shares			Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2009		1,484		$	39.88
Granted		463			38.80
Vested		(618	)		43.54
Cancelled and forfeited		(39	)		36.92
Converted from goal-based stock to restricted stock		186			40.84
Nonvested at December 31, 2010		1,476		$	38.20
Granted		299			43.68
Vested		(617	)		40.72
Cancelled and forfeited		(25	)		36.29
Converted from goal-based stock to restricted stock		168			30.99
Nonvested at December 31, 2011		1,301		$	37.37
Granted		390			51.14
Vested		(596	)		33.31
Cancelled and forfeited		(10	)		42.99
Nonvested at December 31, 2012		1,085		$	44.46

As of December 31, 2012, unrecognized compensation cost related to nonvested restricted stock awards totaled $23 million and is expected to be recognized over a weighted-average period of 2.1 years. The fair value of restricted stock awards that vested was $30 million, $28 million, and $26 million in 2012, 2011 and 2010, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion stock and the applicable federal, state and local tax withholding rates.

GOAL-BASED STOCK

Goal-based stock awards are granted under Dominion’s LTIP to officers who have not achieved a certain targeted level of share ownership, in lieu of cash-based performance grants. Goal-based stock awards may also be made to certain key non-officer employees from time to time. Current outstanding goal-based shares include awards granted to officers in February 2011 and February 2012.

The issuance of awards is based on the achievement of two performance metrics during a two-year period, including TSR relative to that of a peer group of companies and ROIC for 2011 and, for 2012, the two metrics of TSR relative to that of companies listed as members of the Philadelphia Stock Exchange Utility Index as of the end of the performance period and ROIC. The actual number of shares issued will vary between zero and 200% of targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is equal to the market price of Dominion’s stock on the date of grant. Goal-based stock awards granted to key non-officer employees convert to restricted stock at the end

105

Combined Notes to Consolidated Financial Statements, Continued

of the two-year performance period and generally vest three years from the original grant date. Awards to officers vest at the end of the two-year performance period. All goal-based stock awards are settled by issuing new shares.

After the performance period for the April 2009 grants ended on December 31, 2010, the CGN Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 132 thousand shares of the outstanding goal-based stock awards granted in April 2009 were converted to 168 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2012. For awards to officers, 20 thousand shares of the outstanding goal-based stock awards were converted to 25 thousand non-restricted shares and issued to the officers.

After the performance period for the April 2010 grants ended on December 31, 2011, the CGN Committee determined the actual performance against metrics established for those awards. For awards to officers, 9 thousand shares of the outstanding goal-based stock awards were converted to 15 thousand non-restricted shares and issued to the officers.

The following table provides a summary of goal-based stock activity for the years ended December 31, 2012, 2011 and 2010:

	Targeted Number of Shares			Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2009		323		$	36.12
Granted		9			37.46
Vested		(16	)		39.31
Cancelled and forfeited		(8	)		30.99
Converted from goal-based stock to restricted stock		(147	)		40.84
Nonvested at December 31, 2010		161		$	31.79
Granted		3			43.54
Vested		(20	)		34.62
Converted from goal-based stock to restricted stock		(132	)		30.99
Nonvested at December 31, 2011		12		$	39.19
Granted		1			52.48
Vested		(9	)		37.46
Nonvested at December 31, 2012		4		$	45.60

At December 31, 2012, the targeted number of shares expected to be issued under the February 2011 and February 2012 awards was approximately 4 thousand. In January 2013, the CGN Committee determined the actual performance against metrics established for the February 2011 awards with a performance period that ended December 31, 2012. Based on that determination, the total number of shares to be issued under the February 2011 goal-based stock awards was approximately 2 thousand.

As of December 31, 2012, unrecognized compensation cost related to nonvested goal-based stock awards was not material.

CASH-BASED PERFORMANCE GRANTS

Cash-based performance grants are made to Dominion’s officers under Dominion’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.

The targeted amount of the cash-based performance grant

made to officers in April 2009 was $11 million, but the actual payout of the award in February 2011 determined by the CGN Committee was $14 million ($11 million of which was paid in December 2010), based on the level of performance metrics achieved.

In February 2010, a cash-based performance grant was made to officers. A portion of the grant, representing $14 million was paid in December 2011, based on the achievement of two performance metrics during 2010 and 2011: ROIC and TSR relative to that of a peer group of companies. The total amount of the award under the grant was $20 million and the remaining $6 million of the grant was paid in February 2012. At December 31, 2011, a liability of $5 million had been accrued for the remaining portion of the award.

In February 2011, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $6 million was paid in December 2012, based on the achievement of two performance metrics during 2011 and 2012: TSR relative to that of a peer group of companies and ROIC. The total expected award under the grant is $8 million and the remaining portion of the grant is expected to be paid by March 15, 2013. At December 31, 2012, a liability of $2 million had been accrued for the remaining portion of the award.

In February 2012, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2014 based on the achievement of two performance metrics during 2012 and 2013: TSR relative to that of companies listed as members of the Philadelphia Stock Exchange Utility Index as of the end of the performance period and ROIC. At December 31, 2012, the targeted amount of the grant was $12 million and a liability of $6 million had been accrued for this award.

NOTE 20. DIVIDEND RESTRICTIONS

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2012, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

Certain agreements associated with Dominion’s and Virginia Power’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s or Virginia Power’s ability to pay dividends or receive dividends from their subsidiaries at December 31, 2012.

See Note 17 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes.

NOTE 21. EMPLOYEE BENEFIT PLANS

DOMINION

Dominion provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit plans, Dominion reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the

106

employee’s compensation. Dominion’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension program also provides benefits to certain retired executives under a company-sponsored nonqualified employee benefit plan. The nonqualified plan is funded through contributions to a grantor trust. Dominion also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service.

Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and the rate of compensation increases.

Dominion uses December 31 as the measurement date for all of its employee benefit plans. Dominion uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.

Dominion’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Aggregate actual returns for Dominion’s pension and other postretirement plan assets were $743 million in 2012 and $273 million in 2011, versus expected returns of $509 million and $519 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

In January 2011, Dominion amended its retiree healthcare and life benefits to change the eligibility age, effective January 1, 2012, for the majority of nonunion employees from 55 with 10 years of service to 58 with 10 years of service, resulting in an approximately $71 million reduction to the other postretirement benefit plan obligation. The eligibility requirements for nonunion employees hired on or after January 1, 2008, who benefit under the Retiree Medical Account design, as well as for union employees were not affected by this plan design change.

The Medicare Act introduced a federal subsidy to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Dominion determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D. Dominion received a federal subsidy of $5 million for each of 2012 and 2011. In December 2011, Dominion elected to change its method of receiving the subsidy under Medicare Part D for retiree prescription drug coverage

from the Retiree Drug Subsidy to the EGWP. This change became effective January 1, 2013. As a result of this change, Dominion recognized a decrease in its other postretirement benefit obligations of approximately $170 million as of December 31, 2011. As a result of the adoption of the EGWP, beginning in 2013 Dominion will receive an increased level of Medicare Part D subsidies, in the form of reduced costs rather than a direct reimbursement.

Funded Status

The following table summarizes the changes in Dominion’s pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status:

	Pension Benefits						Other Postretirement Benefits
Year Ended December 31,	2012			2011			2012			2011
(millions, except percentages)
Changes in benefit obligation:
Benefit obligation at beginning of year	$	4,981		$	4,490		$	1,493		$	1,707
Service cost		116			108			44			48
Interest cost		268			258			79			94
Benefits paid		(208	)		(215	)		(88	)		(83	)
Actuarial (gains) losses during the year		967			340			191			(210	)
Plan amendments		1			—			1			(70	)
Settlements and curtailments		—			—			(6	)		(1	)
Medicare Part D reimbursement		—			—			5			5
Early Retirement Reimbursement Program		—			—			—			3
Benefit obligation at end of year	$	6,125		$	4,981		$	1,719		$	1,493
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	5,145		$	5,106		$	1,042		$	1,031
Actual return on plan assets		611			247			132			26
Employer contributions		5			7			16			19
Benefits paid		(208	)		(215	)		(34	)		(34	)
Fair value of plan assets at end of year	$	5,553		$	5,145		$	1,156		$	1,042
Funded status at end of year	$	(572	)	$	164		$	(563	)	$	(451	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets		701			677			1			4
Other current liabilities		(2	)		(3	)		(4	)		(3	)
Noncurrent pension and other postretirement benefit liabilities		(1,271	)		(510	)		(560	)		(452	)
Net amount recognized	$	(572	)	$	164		$	(563	)	$	(451	)
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate		4.4	%		5.5	%		4.4	%		5.5	%
Weighted average rate of increase for compensation		4.21	%		4.21	%		4.22	%		4.22	%

107

Combined Notes to Consolidated Financial Statements, Continued

The ABO for all of Dominion’s defined benefit pension plans was $5.5 billion and $4.5 billion at December 31, 2012 and 2011, respectively.

Under its funding policies, Dominion evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion determines the amount of contributions for the current year, if any, at that time. During 2012, Dominion made no contributions to its qualified defined benefit pension plans and no contributions are currently expected in 2013. In July 2012, the Moving Ahead for Progress in the 21st Century Act was signed into law. This Act includes an increase in the interest rates used to determine plan sponsors’ pension contributions for required funding purposes. These new interest rates are expected to reduce required pension contributions for 2013 through 2015. Dominion believes that required pension contributions will rise subsequent to 2015, resulting in little net impact to cumulative required contributions over a 10-year period.

Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion’s subsidiaries fund other postretirement benefit costs through VEBAs. Dominion’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion expects to contribute approximately $14 million to the Dominion VEBAs in 2013.

Dominion does not expect any pension or other postretirement plan assets to be returned to the Company during 2013.

The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets:

	Pension Benefits				Other Postretirement Benefits
As of December 31,	2012		2011		2012		2011
(millions)
Benefit obligation	$	5,462	$	4,416	$	1,591	$	1,375
Fair value of plan assets	$	4,189		3,903		1,027		920

The following table provides information on the ABO and fair value of plan assets for pension plans with an ABO in excess of plan assets:

As of December 31,	2012(1)		2011
(millions)
Accumulated benefit obligation	$	4,850		$	95
Fair value of plan assets		4,189	—

(1) The increase from 2011 is primarily due to a decrease in the discount rate.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Estimated Future Benefit Payments
	Pension Benefits		Other Postretirement Benefits
(millions)
2013	$	231	$	89
2014		245		93
2015		255		96
2016		300		100
2017		334		103
2018-2022		1,749		555

Plan Assets

Dominion’s overall objective for investing its pension and other postretirement plan assets is to achieve the best possible long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for its pension funds are 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the United States. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the United States including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity REITs and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.

Strategic investment policies are established for Dominion’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.

For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.

108

The fair values of Dominion’s pension plan assets by asset category are as follows:

	Fair Value Measurements
	Pension Plans
At December 31,	2012								2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	—	$	195	$	—	$	195	$	1	$	84	$	—	$	85
U.S. equity:
Large Cap		927		104		—		1,031		805		123		—		928
Other		425		99		—		524		359		197		—		556
Non-U.S. equity:
Large Cap		313		68		—		381		253		58		—		311
Other		228		167		—		395		190		81		—		271
Fixed income:
Corporate debt instruments		27		1,026		—		1,053		36		834		—		870
U.S. Treasury securities and agency debentures		331		304		—		635		304		392		—		696
State and municipal		1		71		—		72		2		77		—		79
Other securities		5		43		—		48		8		40		—		48
Real estate:
REITs		29		—		—		29		16		—		—		16
Partnerships		—		—		321		321		—		—		304		304
Other alternative investments:
Private equity		—		—		456		456		—		—		448		448
Debt		—		—		192		192		—		—		243		243
Hedge funds		—		—		221		221		—		—		290		290
Total	$	2,286	$	2,077	$	1,190	$	5,553	$	1,974	$	1,886	$	1,285	$	5,145

The fair values of Dominion’s other postretirement plan assets by asset category are as follows:

	Fair Value Measurements
	Other Postretirement Plans
At December 31,	2012								2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	—	$	13	$	—	$	13	$	—	$	5	$	—	$	5
U.S. equity:
Large Cap		378		5		—		383		38		288		—		326
Other		21		45		—		66		17		44		—		61
Non-U.S. equity:
Large Cap		93		3		—		96		77		3		—		80
Other		11		8		—		19		9		4		—		13
Fixed income:
Corporate debt instruments		1		160		—		161		2		149		—		151
U.S. Treasury securities and agency debentures		16		266		—		282		14		246		—		260
State and municipal		—		9		—		9		—		6		—		6
Other securities		—		2		—		2		—		2		—		2
Real estate:
REITs		1		—		—		1		1		—		—		1
Partnerships		—		—		24		24		—		—		24		24
Other alternative investments:
Private equity		—		—		58		58		—		—		63		63
Debt		—		—		31		31		—		—		36		36
Hedge funds		—		—		11		11		—		—		14		14
Total	$	521	$	511	$	124	$	1,156	$	158	$	747	$	137	$	1,042

109

Combined Notes to Consolidated Financial Statements, Continued

The following table presents the changes in Dominion’s pension and other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category:

	Fair Value Measurements using Significant Unobservable Inputs (Level 3)
	Pension Plans															Other Postretirement Plans
	Real Estate			Private Equity			Debt			Hedge Funds			Total			Real Estate			Private Equity			Debt			Hedge Funds			Total
Balance at December 31, 2009	$344			$344			$241			$388			$1,317			$26			$54			$36			$19			$135
Actual return on plan assets:
Relating to assets still held at the reporting date		8			56			27			27			118			—			9			2			1			12
Purchases		56			90			36			—			182			3			9			8			—			20
Sales		(137	)		(90	)		(42	)		(70	)		(339	)		(7	)		(11	)		(6	)		(3	)		(27	)
Balance at December 31, 2010	$	271		$	400		$	262		$	345		$	1,278		$	22		$	61		$	40		$	17		$	140
Actual return on plan assets:
Relating to assets still held at the reporting date		38			70			10			10			128			3			11			1			—			15
Relating to assets sold during the period		(8	)		(34	)		(10	)		(15	)		(67	)		—			(4	)		(1	)		(1	)		(6	)
Purchases		57			76			34			48			215			3			8			3			2			16
Sales		(54	)		(64	)		(53	)		(98	)		(269	)		(4	)		(13	)		(7	)		(4	)		(28	)
Balance at December 31, 2011	$	304		$	448		$	243		$	290		$	1,285		$	24		$	63		$	36		$	14		$	137
Actual return on plan assets:
Relating to assets still held at the reporting date		21			46			17			21			105			1			3			4			1			9
Relating to assets sold during the period		(8	)		(41	)		(11	)		(2	)		(62	)		—			(1	)		—			—			(1	)
Purchases		35			79			15			—			129			2			6			1			—			9
Sales		(31	)		(76	)		(72	)		(88	)		(267	)		(3	)		(13	)		(10	)		(4	)		(30	)
Balance at December 31, 2012	$	321		$	456		$	192		$	221		$	1,190		$	24		$	58		$	31		$	11		$	124

Net Periodic Benefit Cost

The components of the provision for net periodic benefit cost and amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2012			2011			2010			2012			2011			2010
(millions, except percentages)
Service cost	$	116		$	108		$	102		$	44		$	48		$	56
Interest cost		268			258			266			79			94			101
Expected return on plan assets		(430	)		(440	)		(410	)		(79	)		(79	)		(69	)
Amortization of prior service (credit) cost		3			3			3			(13	)		(13	)		(7	)
Amortization of net actuarial loss		132			96			59			6			12			12
Settlements and curtailments(1)		—			—			136			(4	)		1			37
Special termination benefits(2)		—			—			10			—			—			1
Net periodic benefit cost	$	89		$	25		$	166		$	33		$	63		$	131
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	786		$	534		$	95		$	139		$	(157	)	$	13
Prior service (credit) cost		—			—			1			1			(70	)		—
Settlements and curtailments(1)		—			—			(50	)		(2	)		(1	)		(1	)
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss		(132	)		(96	)		(59	)		(6	)		(12	)		(12	)
Amortization of prior service credit (cost)		(3	)		(3	)		(3	)		13			13			7
Total recognized in other comprehensive income and regulatory assets and liabilities	$	651		$	435		$	(16	)	$	145		$	(227	)	$	7
Significant assumptions used to determine periodic cost:
Discount rate		5.5	%		5.9	%		6.6	%		5.5	%		5.9	%		6.6	%
Expected long-term rate of return on plan assets		8.5	%		8.5	%		8.5	%		7.75	%		7.75	%		7.75	%
Weighted average rate of increase for compensation		4.21	%		4.61	%		4.76	%		4.22	%		4.62	%		4.79	%
Healthcare cost trend rate(3)											7	%		7	%		7	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(3)											4.6	%		4.6	%		4.6	%
Year that the rate reaches the ultimate trend rate(3)											2061			2060			2060

(1) 2012 amounts relate to the sale of Salem Harbor. 2010 amounts relate to the sales of Peoples and Dominion’s Appalachian E&P operations and a workforce reduction program.

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

(3) Assumptions used to determine periodic cost for the following year.

110

The components of AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit cost are as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2012		2011		2012			2011
(millions)
Net actuarial loss	$	2,865	$	2,211	$	229		$	100
Prior service (credit) cost		11		14		(71	)		(86	)
Total(1)	$	2,876	$	2,225	$	158		$	14

(1) As of December 31, 2012, of the $2.9 billion and $158 million related to pension benefits and other postretirement benefits, $1.8 billion and $69 million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2011, of the $2.2 billion related to pension benefits, $1.4 billion is included in AOCI, with the remainder included in regulatory assets and liabilities; the $14 million related to other postretirement benefits consists of $16 million included in regulatory assets and liabilities and $(2) million included in AOCI.

The following table provides the components of AOCI and regulatory assets and liabilities as of December 31, 2012 that are expected to be amortized as components of periodic benefit cost in 2013:

	Pension Benefits		Other Postretirement Benefits
(millions)
Net actuarial loss	$	185	$	9
Prior service (credit) cost		3		(12	)

Dominion determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans by using a combination of:

• Expected inflation and risk-free interest rate assumptions;

• Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;

• Expected future risk premiums, asset volatilities and correlations;

• Forecasts of an independent investment advisor;

• Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; and

• Investment allocation of plan assets.

Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans.

Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion’s retiree healthcare plans. A one percentage point change in assumed healthcare cost trend rates would have had the following effects:

	Other Postretirement Benefits
	One percentage point increase		One percentage point decrease
(millions)
Effect on total of service and interest cost components for 2012	$	17	$	(16	)
Effect on other postretirement benefit obligation at December 31, 2012		218		(172	)

An internal committee selects the final assumptions used for Dominion’s pension and other postretirement plans, including discount rates, expected long-term rates of return and healthcare cost trend rates.

Defined Contribution Plans

In addition, Dominion sponsors defined contribution employee savings plans. During 2012, 2011 and 2010, Dominion recognized $40 million, $38 million and $39 million, respectively, as employer matching contributions to these plans.

VIRGINIA POWER

Virginia Power participates in the Dominion Pension Plan, a defined benefit pension plan sponsored by Dominion that provides benefits to multiple Dominion subsidiaries. Retirement benefits payable under this plan are based primarily on years of service, age and the employee’s compensation. As a participating employer, Virginia Power is subject to Dominion’s funding policy, which is to contribute annually an amount that is in accordance with the provisions of ERISA. During 2012, Virginia Power made no contributions to the plan and no contributions are currently expected in 2013. Virginia Power’s net periodic pension cost related to this pension plan was $72 million, $50 million and $84 million in 2012, 2011 and 2010, respectively. Employee compensation is the basis for determining Virginia Power’s share of total pension costs.

Virginia Power also participates in the Dominion Retiree Health and Welfare Plan, a plan sponsored by Dominion that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Annual employee premiums are based on several factors such as age, retirement date and years of service. Virginia Power’s net periodic benefit cost related to this plan was $13 million, $23 million and $59 million in 2012, 2011 and 2010, respectively. Employee headcount is the basis for determining Virginia Power’s share of total other postretirement benefit costs.

Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power funds other postretirement benefit costs through a VEBA. Virginia Power made no contributions to the VEBA in 2012 and does not expect to contribute to the VEBA in 2013.

111

Combined Notes to Consolidated Financial Statements, Continued

Dominion holds investments in trusts to fund employee benefit payments for its pension and other postretirement benefit plans, in which Virginia Power’s employees participate. Any investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power will provide to Dominion for its share of employee benefit plan contributions.

Virginia Power also participates in Dominion-sponsored defined contribution employee savings plans that cover substantially all employees. Employer matching contributions of $15 million were incurred in 2012 and $14 million in each of 2011 and 2010.

NOTE 22. 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. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. This estimated range is based on currently available information and involves elements of judgment and significant uncertainties. This estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on Dominion’s or Virginia Power’s financial position, liquidity or results of operations.

Environmental Matters

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

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

In December 2011, the EPA issued MATS for coal and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance will be required by April 16, 2015, with certain limited exceptions. In December 2011, Virginia Power recorded a $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain regulated coal units, primarily as a result of the issuance of the final MATS. Dominion continues to be governed by individual state mercury emission reduction regulations in Massachusetts and Illinois that are largely unaffected by this rule.

The EPA established CAIR with the intent to require significant reductions in SO₂ and NO_x emissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO₂ and NO_x emissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO₂ and NO_x emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NO_x emissions caps, NO_x emissions caps during the ozone season (May 1 through September 30) and annual SO₂ emission caps with differing requirements for two groups of affected states.

Following numerous petitions by industry participants for review and motions for stay, the U.S. Court of Appeals for the D.C. Circuit issued a ruling in December 2011 to stay CSAPR pending judicial review. In February and June 2012, the EPA issued technical revisions to CSAPR that are not material to Dominion. In August 2012, the Court vacated CSAPR in its entirety and ordered the EPA to implement CAIR until a valid replacement rule is issued. In October 2012, the EPA filed a petition requesting a rehearing of the court’s decision, which was denied in January 2013. The mandate vacating CSAPR was issued February 4, 2013. The stay of CSAPR remains in effect and the EPA will continue to administer CAIR until such time that the EPA develops and implements new rulemaking addressing the issues identified by the Court. With respect to Dominion’s generation fleet, the cost to comply with CAIR is not expected to be material. Future outcomes of litigation and/or any additional action to issue a revised rule could affect the assessment regarding cost of compliance.

112

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

In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, NSPS, the Title V permit program and the stations’ respective State Implementation Plans. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the CAA. In May 2010, 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 Brayton Point. Dominion submitted its response to the request in November 2010.

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

WATER

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

In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling

water. As of the end of the third quarter of 2012, the station was fully converted to closed cycle cooling. The total cost to install these cooling towers was approximately $550 million. See Note 6 for a discussion of impairments related to Brayton Point.

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

SOLID AND HAZARDOUS WASTE

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

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

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

The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO

113

Combined Notes to Consolidated Financial Statements, Continued

without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO. Virginia Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter.

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

CLIMATE CHANGE LEGISLATION AND REGULATION

Massachusetts, Rhode Island and Connecticut, among other states, have joined RGGI, a multi-state effort to reduce CO₂ emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO₂ emissions from power plants in participating states are required to be stabilized at current levels from 2009 to 2015. Further reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO₂ emissions. During 2012, RGGI underwent a program review, and in February 2013, revisions to the RGGI model rule were issued. Dominion is in the process of evaluating these revisions as to potential impacts on Dominion’s fossil fired generation operations in RGGI states. Until this evaluation is completed, Dominion is unable to estimate the potential financial statement impacts related to the program review.

Two of Dominion’s facilities, Brayton Point and Manchester Street, are subject to RGGI. Beginning with calendar year 2009, RGGI requires that Dominion cover each ton of 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 periodically participated in RGGI allowance auctions to date and has procured allowances to meet its estimated compliance requirements under RGGI’s current requirement through 2013 and most of 2014, therefore Dominion does not expect compliance with RGGI to have a material impact on its results of operations or financial condition. During June 2011, a lawsuit was filed in New York seeking to retroactively rescind RGGI participation by that state. A percentage of Dominion’s RGGI allowances had been acquired from New York. The allocated value of these allowances totaled approximately $38 million, of which all have been expensed as consumed for RGGI Phase I compliance. In February 2012, Dominion surrendered these New York RGGI allowances for the

RGGI Phase I compliance period and therefore does not expect any significant financial statement impacts from this lawsuit as it no longer holds allowances issued by the state of New York. In June 2012, a New York state court dismissed the lawsuit. A notice of appeal was filed in July 2012, however no appeal was filed.

MF Global

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

In accordance with court-approved procedures, Dominion transferred to other FCMs all open positions executed using MF Global. The initial margin posted for these open positions at October 31, 2011 was approximately $73 million. Dominion had received approximately $17 million of this amount through the liquidation process as of December 31, 2012. In January 2013, Dominion sold the remaining claims of approximately $56 million to a third party at a small discount.

Nuclear Matters

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

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

Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion require implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation. The orders require prompt implementation of the safety enhancements and completion of implementation within two refueling outages or by December 31, 2016, whichever comes first. The information requests issued by

114

the NRC request each reactor to reevaluate the seismic and flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. Dominion and Virginia Power do not currently expect that compliance with the NRC’s March 2012 orders and information requests will materially impact their financial position, results of operations or cash flows during the approximately four-year implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion and Virginia Power are currently unable to estimate the potential financial impacts related to compliance with Tier 2 and Tier 3 recommendations.

Long-Term Purchase Agreements

At December 31, 2012, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:

	2013		2014		2015		2016		2017		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	350	$	358	$	337	$	275	$	181	$	327	$	1,828

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2012, the present value of Virginia Power’s total commitment for capacity payments is $1.4 billion. Capacity payments totaled $337 million, $338 million, and $344 million, and energy payments totaled $214 million, $275 million, and $303 million for 2012, 2011 and 2010, respectively.

Lease Commitments

Dominion and Virginia Power lease various facilities, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2012 are as follows:

	2013		2014		2015		2016		2017		Thereafter		Total
(millions)
Dominion	$	79	$	72	$	64	$	55	$	63	$	161	$	494
Virginia Power	$	26	$	24	$	19	$	15	$	11	$	26	$	121

Rental expense for Dominion totaled $112 million, $155 million, and $171 million for 2012, 2011 and 2010, respectively. Rental expense for Virginia Power totaled $48 million, $50 million, and $50 million for 2012, 2011, and 2010, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.

Nuclear Operations

NUCLEAR DECOMMISSIONING—MINIMUM FINANCIAL ASSURANCE

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 2012 calculation for the NRC minimum financial assurance amount, aggregated for Dominion’s and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts, was $3.3 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2012 NRC minimum financial assurance amounts shown were calculated using preliminary December 31, 2012 U.S. Bureau of Labor Statistics indices. Dominion believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion and Virginia Power will continue to monitor these trusts to ensure they meet the minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC. See Note 6 to the Consolidated Financial Statements for additional information on Kewaunee.

NUCLEAR INSURANCE

The Price-Anderson Amendments Act of 1988 provides the public up to $12.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $118 million for each of their licensed reactors not to exceed $18 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

The current level of property insurance coverage for Dominion’s and Virginia Power’s nuclear units is as follows:

	Coverage
(billions)
Dominion
Millstone	$	2.75
Kewaunee		1.80
Virginia Power(1)
Surry	$	2.55
North Anna		2.55

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

115

Combined Notes to Consolidated Financial Statements, Continued

The Companies’ coverage exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $89 million and $48 million, respectively. Based on the severity of the incident, the Board of Directors of NEIL has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

Dominion and Virginia Power also purchase insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, the Companies are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $33 million and $20 million, respectively.

During the fourth quarter of 2012, Dominion announced plans to close and decommission Kewaunee. Kewaunee is expected to cease power production in the second quarter of 2013 and commence decommissioning activities. Effective February 1, 2013, Kewaunee’s accidental outage policy for replacement power costs has been cancelled, and Kewaunee’s property coverage of $1.8 billion did not change. The cancellation of Kewaunee’s accidental outage policy for replacement power costs lowered Dominion’s retrospective premium assessment from $33 million to $30 million.

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

SPENT NUCLEAR FUEL

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

Dominion and Virginia Power have resolved additional claims for damages incurred at Millstone, Kewaunee, Surry and North Anna. In May 2012, Dominion made formal offers of settlement to the Authorized Representative of the Attorney General for resolution of claims incurred at Millstone for the period July 1,

2006 through December 31, 2010 and periodic payments after that date through 2013 and for resolution of claims incurred at Kewaunee for the period January 1, 2009 through December 31, 2010 and periodic payments after that date through 2013. In September 2012, Dominion and the government entered into settlement agreements. Initial settlement payments in the amounts of $20 million for Millstone and $6 million for Kewaunee were received in the fourth quarter of 2012. In September 2012, Virginia Power made a formal offer of settlement for resolution of claims incurred at Surry and North Anna for the period July 1, 2006 through December 31, 2010 and periodic payments after that date through 2013. In November 2012, Virginia Power and the government entered into a settlement agreement. An initial settlement payment in the amount of $75 million for Surry and North Anna was received in the fourth quarter of 2012. All of the settlement agreements are extendable after 2013 by mutual agreement of the parties. In June 2012, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims for Millstone, Surry and North Anna against the DOE requesting additional damages for the period July 1, 2006 through December 31, 2010. The lawsuits have been dismissed as a result of the settlement agreements.

The Companies continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion’s receivables for spent nuclear fuel-related costs totaled $36 million and $102 million at December 31, 2012 and 2011, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $26 million and $76 million at December 31, 2012 and 2011, respectively. The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Guarantees, Surety Bonds and Letters of Credit

DOMINION

At December 31, 2012, Dominion had issued $92 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2012, Dominion’s exposure under these guarantees was $62 million, primarily related to certain reserve requirements associated with non-recourse financing.

In addition to the above guarantees, Dominion and its partners, Shell and BP, may be required to make additional periodic equity contributions to NedPower and Fowler Ridge in connection with certain funding requirements associated with their respective non-recourse financings. As of December 31, 2012, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $107 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million.

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

116

unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.

At December 31, 2012, Dominion had issued the following subsidiary guarantees:

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	363	$	363
Commodity transactions(3)		2,939		377
Nuclear obligations(4)		231		77
Other(5)		673		98
Total	$	4,206	$	915

(1) Represents the estimated portion of the guarantee’s stated limit that is utilized as of December 31, 2012 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount.

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

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

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

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

Additionally, as of December 31, 2012 Dominion had purchased $163 million of surety bonds and authorized the issuance of letters of credit by financial institutions of $26 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Dominion is obligated to indemnify the respective surety bond company for any amounts paid.

VIRGINIA POWER

As of December 31, 2012, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. Virginia Power had also purchased $67 million of surety bonds for various purposes, including providing workers’ compensation coverage, and authorized the issuance of letters of credit by financial institutions of $2 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Virginia Power is obligated to indemnify the respective surety bond company for any amounts paid.

Indemnifications

As part of commercial contract negotiations in the normal course of business, Dominion and Virginia Power may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. Dominion and Virginia Power are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2012, Dominion and Virginia Power believe future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.

Workforce Reduction Program

In the first quarter of 2010, Dominion and Virginia Power announced a workforce reduction program that reduced their total workforces by approximately 9% and 11%, respectively, during 2010. The goal of the workforce reduction program was to reduce operations and maintenance expense growth and further improve the efficiency of the Companies. In the first quarter of 2010, Dominion recorded a $338 million ($206 million after-tax) charge, including $202 million ($123 million after-tax) at Virginia Power, primarily reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other benefits related to the workforce reduction program. During 2010, Dominion and Virginia Power paid $109 million and $104 million, respectively, of costs related to the program. The terms of the workforce reduction program were consistent with the Companies’ existing severance plan.

NOTE 23. CREDIT RISK

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

Dominion and Virginia Power maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 2012 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

GENERAL

DOMINION

As a diversified energy company, Dominion transacts primarily with major companies in the energy industry and with commer-

117

Combined Notes to Consolidated Financial Statements, Continued

cial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.

Dominion’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include trading of energy-related commodities, marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2012, Dominion’s credit exposure totaled $512 million. Of this amount, investment grade counterparties, including those internally rated, represented 77%. One counterparty exposure represents 11% of Dominion’s total exposure and is a large financial institution rated investment grade.

VIRGINIA POWER

Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2012, Virginia Power’s exposure to potential concentrations of credit risk was not considered material.

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 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 December 31, 2012 and 2011, Dominion would have been required to post an additional $110 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 $4 million in collateral at December 31, 2012 and $110 million in collateral, including $4 million of letters of credit at December 31, 2011, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 2012 and 2011 was $163 million and $259 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power were not material as of December 31, 2012 and 2011. See Note 7 for further information about derivative instruments.

NOTE 24. 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 risks associated with purchases of natural gas.

As of December 31, 2012 and 2011, Virginia Power’s derivative liabilities with affiliates were not material.

DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage. Presented below are significant transactions with DRS and other affiliates:

Year Ended December 31,	2012		2011		2010
(millions)
Commodity purchases from affiliates	$	368	$	376	$	373
Services provided by affiliates		399		393		469
Services provided to affiliates		19		21		19

In the fourth quarter of 2011, a subsidiary of Virginia Power purchased nuclear fuel-related inventory from an affiliate for $39 million for future use at its nuclear generation stations.

Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were $243 million in short-term demand note borrowings from Dominion as of December 31, 2012. There were no short-term demand note borrowings from Dominion as of December 31, 2011. Virginia

118

Power’s outstanding borrowings, net of repayments, under the Dominion money pool for its nonregulated subsidiaries totaled $192 million and $187 million as of December 31, 2012 and 2011, respectively. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the years ended December 31, 2012, 2011 and 2010.

In 2010 Virginia Power issued 33,013 shares of its common stock to Dominion for approximately $1 billion, for the purpose of retiring short-term demand note borrowings from Dominion. There were no such issuances of common stock in 2011 and 2012.

NOTE 25. OPERATING SEGMENTS

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

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

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

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

The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of the operations that are expected to be or are currently discontinued, which are discussed in Note 3. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

DOMINION

In 2012, Dominion reported after-tax net expense of $1.4 billion for specific items in the Corporate and Other segment, with $1.4 billion of these net expenses attributable to its operating segments.

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

Ÿ A $1.7 billion ($1.1 billion after-tax) net loss from operations, including an impairment charge, of Brayton Point, Kincaid and Elwood, attributable to Dominion Generation. Dominion announced its intention to pursue the sale of these two merchant power stations and equity method investment in the third quarter of 2012;

Ÿ A $467 million ($303 million after-tax) net loss, including impairment charges, primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013, attributable to Dominion Generation;

Ÿ An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP; and

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

In 2011, Dominion reported after-tax net expense of $311 million for specific items in the Corporate and Other segment, with $340 million of these net expenses attributable to its operating segments.

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

Ÿ A $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units, attributable to Dominion Generation;

Ÿ A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP;

Ÿ A $66 million ($39 million after-tax) loss from the operations of Kewaunee, attributable to Dominion Generation;

Ÿ 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

Ÿ A $34 million ($25 million after-tax) loss from discontinued operations of State Line and Salem Harbor which were sold in 2012, attributable to Dominion Generation.

In 2010, Dominion reported after-tax net benefits of $865 million for specific items in the Corporate and Other segment, with $1.0 billion of these net benefits attributable to its operating segments.

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

Ÿ 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

Ÿ A $331 million ($202 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program, attributable to:

Ÿ DVP ($67 million after-tax);

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

Ÿ Dominion Generation ($111 million after-tax);

Ÿ A $158 million ($103 million after-tax) loss from the discontinued operations of State Line and Salem Harbor; and

Ÿ A $134 million ($155 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.

119

Combined Notes to Consolidated Financial Statements, Continued

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

Year Ended December 31,	DVP		Dominion Generation(1)		Dominion Energy		Corporate and Other(1)			Adjustments & Eliminations			Consolidated Total
(millions)
2012
Total revenue from external customers	$	3,385	$	6,517	$	1,813	$	307		$	1,071		$	13,093
Intersegment revenue		112		333		930		608			(1,983	)		—
Total operating revenue		3,497		6,850		2,743		915			(912	)		13,093
Depreciation, depletion and amortization		402		500		216		68			—			1,186
Equity in earnings of equity method investees		—		3		23		(1	)		—			25
Interest income		9		57		30		71			(106	)		61
Interest and related charges		187		208		47		546			(106	)		882
Income taxes		351		479		352		(1,036	)		—			146
Loss from discontinued operations, net of tax		—		—		—		(22	)		—			(22	)
Net income (loss) attributable to Dominion		559		874		551		(1,682	)		—			302
Investment in equity method investees		1		414		141		2			—			558
Capital expenditures		1,158		1,615		1,350		22			—			4,145
Total assets (billions)		12.1		21.2		11.2		12.6			(10.3	)		46.8
2011
Total revenue from external customers	$	3,663	$	7,080	$	2,044	$	55		$	1,303		$	14,145
Intersegment revenue		173		355		1,077		596			(2,201	)		—
Total operating revenue		3,836		7,435		3,121		651			(898	)		14,145
Depreciation, depletion and amortization		374		457		207		28			—			1,066
Equity in earnings of equity method investees		—		3		23		9			—			35
Interest income		22		54		27		70			(106	)		67
Interest and related charges		185		217		57		514			(106	)		867
Income taxes		318		583		323		(470	)		—			754
Loss from discontinued operations, net of tax		—		—		—		(25	)		—			(25	)
Net income (loss) attributable to Dominion		501		968		521		(582	)		—			1,408
Investment in equity method investees		8		415		104		26			—			553
Capital expenditures		1,091		1,593		907		61			—			3,652
Total assets (billions)		11.5		22.1		10.6		11.4			(10.0	)		45.6
2010
Total revenue from external customers	$	3,613	$	7,735	$	2,335	$	19		$	1,225		$	14,927
Intersegment revenue		207		413		1,166		750			(2,536	)		—
Total operating revenue		3,820		8,148		3,501		769			(1,311	)		14,927
Depreciation, depletion and amortization		353		443		210		29			—			1,035
Equity in earnings of equity method investees		—		11		21		10			—			42
Interest income		12		45		12		92			(90	)		71
Interest and related charges		158		179		85		494			(90	)		826
Income taxes		277		756		302		777			—			2,112
Loss from discontinued operations, net of tax		—		—		—		(258	)		—			(258	)
Net income attributable to Dominion		448		1,263		475		622			—			2,808
Capital expenditures		1,038		1,742		613		29			—			3,422

(1) Segment information has been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

At December 31, 2012, 2011, and 2010, none of Dominion’s long-lived assets and no significant percentage of its operating revenues were associated with international operations.

120

VIRGINIA POWER

The majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s DVP and Dominion Generation segments.

In 2012, Virginia Power reported after-tax net expenses of $51 million for specific items attributable to its operating segments in the Corporate and Other segment.

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

Ÿ An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP.

In 2011, Virginia Power reported after-tax net expenses of $268 million 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:

Ÿ A $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired generating units, attributable to Dominion Generation;

Ÿ A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP; and

Ÿ 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.

In 2010, Virginia Power reported after-tax net expenses of $153 million for specific items attributable to its operating segments in the Corporate and Other segment.

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

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

Ÿ DVP ($63 million after-tax); and

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

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

Year Ended December 31,	DVP		Dominion Generation		Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2012
Operating revenue	$	1,847	$	5,379	$	—		$	—		$	7,226
Depreciation and amortization		392		390		—			—			782
Interest income		1		7		—			—			8
Interest and related charges		186		199		—			—			385
Income taxes		277		403		(27	)		—			653
Net income (loss)		448		653		(51	)		—			1,050
Capital expenditures		1,142		1,146		—			—			2,288
Total assets (billions)		11.4		14.8		—			(1.4	)		24.8
2011
Operating revenue	$	1,793	$	5,546	$	(93	)	$	—		$	7,246
Depreciation and amortization		368		350		—			—			718
Interest income		10		8		—			—			18
Interest and related charges		182		199		(50	)		—			331
Income taxes		265		447		(172	)		—			540
Net income (loss)		426		664		(268	)		—			822
Capital expenditures		1,081		1,009		—			—			2,090
Total assets (billions)		10.7		14.3		—			(1.5	)		23.5
2010
Operating revenue	$	1,680	$	5,546	$	(7	)	$	—		$	7,219
Depreciation and amortization		344		327		—			—			671
Interest income		11		4		—			—			15
Interest and related charges		158		189		—			—			347
Income taxes		228		385		(71	)		—			542
Net income (loss)		377		630		(155	)		—			852
Capital expenditures		1,035		1,199		—			—			2,234

121

Combined Notes to Consolidated Financial Statements, Continued

NOTE 26. QUARTERLY FINANCIAL AND COMMON STOCK DATA (UNAUDITED)

A summary of Dominion’s and Virginia Power’s quarterly results of operations for the years ended December 31, 2012 and 2011 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

DOMINION

	First Quarter(2)		Second Quarter			Third Quarter			Fourth Quarter			Full Year
(millions, except per share amounts)
2012
Operating revenue	$	3,462	$	3,053		$	3,411		$	3,167		$	13,093
Income (loss) from operations		913		617			518			(892	)		1,156
Net income (loss) including noncontrolling interests		501		265			215			(652	)		329
Income (loss) from continuing operations(1)		493		276			214			(659	)		324
Income (loss) from discontinued operations(1)		1		(18	)		(5	)		—			(22	)
Net income (loss) attributable to Dominion		494		258			209			(659	)		302
Basic EPS:
Income (loss) from continuing operations(1)		0.86		0.48			0.37			(1.15	)		0.57
Income (loss) from discontinued operations(1)		—		(0.03	)		(0.01	)		—			(0.04	)
Net income (loss) attributable to Dominion		0.86		0.45			0.36			(1.15	)		0.53
Diluted EPS:
Income (loss) from continuing operations(1)		0.86		0.48			0.37			(1.15	)		0.57
Loss from discontinued operations(1)		—		(0.03	)		(0.01	)		—			(0.04	)
Net income (loss) attributable to Dominion		0.86		0.45			0.36			(1.15	)		0.53
Dividends declared per share		0.5275		0.5275			0.5275			0.5275			2.11
Common stock prices (intraday high-low)	$	53.68 - 48.87	$	54.69 - 49.87		$	55.62 - 52.15		$	53.89 - 48.94		$	55.62 - 48.87

	First Quarter			Second Quarter			Third Quarter		Fourth Quarter		Full Year
(millions, except per share amounts)
2011(2)
Operating revenue	$	3,983		$	3,288		$	3,745	$	3,129	$	14,145
Income from operations		993			733			828		340		2,894
Net income including noncontrolling interests		483			340			396		207		1,426
Income from continuing operations(1)		504			341			388		200		1,433
Income (loss) from discontinued operations(1)		(25	)		(5	)		4		1		(25	)
Net income attributable to Dominion		479			336			392		201		1,408
Basic EPS:
Income from continuing operations(1)		0.87			0.59			0.68		0.35		2.50
Income (loss) from discontinued operations(1)		(0.04	)		(0.01	)		0.01		—		(0.04	)
Net income attributable to Dominion		0.83			0.58			0.69		0.35		2.46
Diluted EPS:
Income from continuing operations(1)		0.86			0.59			0.68		0.35		2.49
Income (loss) from discontinued operations(1)		(0.04	)		(0.01	)		0.01		—		(0.04	)
Net income attributable to Dominion		0.82			0.58			0.69		0.35		2.45
Dividends declared per share		0.4925			0.4925			0.4925		0.4925		1.97
Common stock prices (intraday high-low)	$	46.56 - 42.06		$	48.55 - 43.27		$	51.44 - 44.50	$	53.59 - 48.21	$	53.59 - 42.06

(1) Amounts attributable to Dominion’s common shareholders.

(2) Revenue and income amounts have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

Dominion’s 2012 results include the impact of the following significant items:

Ÿ Fourth quarter results include a $1.0 billion after-tax impairment charge to write down Brayton Point’s and Kincaid’s long-lived assets to their estimated fair value.

Ÿ Third quarter results include a $281 million after-tax net loss, including impairment charges, primarily resulting from management’s decision to cease operations and begin decommissioning Kewaunee in 2013.

Dominion’s 2011 results include the impact of the following significant item:

Ÿ Fourth quarter results include a $139 million after-tax charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units.

122

VIRGINIA POWER

Virginia Power’s quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
(millions)
2012
Operating revenue	$	1,754	$	1,756	$	2,086	$	1,630	$	7,226
Income from operations		468		361		746		417		1,992
Net income		243		172		415		220		1,050
Balance available for common stock		239		168		411		216		1,034
2011
Operating revenue	$	1,757	$	1,757	$	2,177	$	1,555	$	7,246
Income from operations		511		471		568		55		1,605
Net income		278		241		297		6		822
Balance available for common stock		274		237		293		1		805

Virginia Power’s 2012 results include the impact of the following significant item:

Ÿ Second quarter results include a $42 million after-tax charge reflecting restoration costs associated with damage caused by late June summer storms.

Virginia Power’s 2011 results include the impact of the following significant item:

Ÿ Fourth quarter results include a $139 million after-tax charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired power stations.

123

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

DOMINION

Senior management, including Dominion’s CEO and CFO, evaluated the effectiveness of Dominion’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion’s CEO and CFO have concluded that Dominion’s disclosure controls and procedures are effective. There were no changes in Dominion’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion’s internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Dominion Resources, Inc. (Dominion) understands and accepts responsibility for Dominion’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion does throughout all aspects of its business.

Dominion maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Audit Committee of the Board of Directors of Dominion, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion’s 2012 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2012, Dominion makes the following assertions:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated Dominion’s internal control over financial reporting as of December 31, 2012. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion maintained effective internal control over financial reporting as of December 31, 2012.

Dominion’s independent registered public accounting firm is engaged to express an opinion on Dominion’s internal control over financial reporting, as stated in their report which is included herein.

February 27, 2013

124

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Dominion Resources, Inc.

Richmond, Virginia

We have audited the internal control over financial reporting of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Dominion’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s Board of Directors, management, and other personnel 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Dominion maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of Dominion and our report dated February 27, 2013, expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2013

125

VIRGINIA POWER

Senior management, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes in 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, Virginia Power’s internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Virginia Electric and Power Company (Virginia Power) understands and accepts responsibility for Virginia Power’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Virginia Power continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.

Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s 2012 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2012, Virginia Power makes the following assertions:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated Virginia Power’s internal control over financial reporting as of December 31, 2012. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2012.

This annual report does not include an attestation report of Virginia Power’s registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.

February 27, 2013

126

Item 9B. Other Information

Explanatory Note: The following information is furnished in this Form 10-K in lieu of being furnished pursuant to Item 2.02 in a Form 8-K. The date of the events reported below was February 28, 2013.

On January 31, 2013, Dominion issued its 4th Quarter 2012 Earnings Release Kit reporting unaudited earnings determined in accordance with GAAP for the 12 months ended December 31, 2012, and a fourth quarter impairment charge related to Brayton Point. On February 28, 2013, Dominion issued a revised 4th Quarter 2012 Earnings Release Kit to reflect a reduction in reported earnings for the 12 months ended December 31, 2012. The reduction relates to an additional impairment charge associated with Dominion’s merchant power stations being marketed for sale. For more information on the impairment charge, see Note 6 to the Consolidated Financial Statements, which information is incorporated herein by reference. The revised Earnings Release Kit reflecting the reduction in earnings and supplemental schedules are furnished with this Form 10-K as Exhibits 99.1 and 99.2, respectively.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

DOMINION

The following information for Dominion is incorporated by reference from the Dominion 2013 Proxy Statement, which will be filed on or around March 19, 2013:

Ÿ Information regarding the directors required by this item is found under the heading Election of Directors.

Ÿ Information regarding compliance with Section 16 of the Securities Exchange Act of 1934, as amended, required by this item is found under the heading Section 16(a) Beneficial Ownership Reporting Compliance.

Ÿ Information regarding the Dominion Audit Committee Financial expert(s) required by this item is found under the headings Director Independence and Committees and Meeting Attendance.

Ÿ Information regarding the Dominion Audit Committee required by this item is found under the headings The Audit Committee Report and Committees and Meeting Attendance.

Ÿ Information regarding Dominion’s Code of Ethics required by this item is found under the heading Corporate Governance and Board Matters.

The information concerning the executive officers of Dominion required by this item is included in Part I of this Form 10-K under the caption Executive Officers of Dominion. Each executive officer of Dominion is elected annually.

VIRGINIA POWER

Information concerning directors of Virginia Power, each of whom is elected annually, is as follows:

Name and Age	Principal Occupation and Directorships in Public Corporations for Last Five Years(1)	Year First Elected as Director
Thomas F. Farrell II (58)	Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date. Mr. Farrell has served as a director of Altria Group, Inc. since 2008. Mr. Farrell’s qualifications to serve as a director include his 17 years of industry experience as well as his legal expertise, having served as General Counsel for Dominion and Virginia Power and as a practicing attorney with a private firm. He is chairman of the Institute of Nuclear Power Operations and a member of the Board of Directors of the Edison Electric Institute through which he actively represents the interests of Dominion, Virginia Power and the energy sector. Mr. Farrell also has extensive community and public interest involvement and serves or has served on many non-profit and university foundations.		1999
Mark F. McGettrick (55)	Executive Vice President and CFO of Virginia Power and Dominion from June 2009 to date; President and COO-Generation of Virginia Power from February 2006 to May 2009; Executive Vice President of Dominion from April 2006 to May 2009. Mr. McGettrick’s qualifications to serve as a director include his more than 30 years of power generation management and industry experience. He currently serves on the George Mason University board of visitors and business council and is on the Board of Directors of the Dominion Foundation. Mr. McGettrick also has community and public interest involvement and serves or has served on many non-profit foundations and boards.		2009
Steven A. Rogers (51)	Senior Vice President and Chief Information Officer of Virginia Power and Dominion from January 2013 to date; Senior Vice President and Chief Administrative Officer of Dominion and President and Chief Administrative Officer of DRS from October 2007 to December 2012. Mr. Roger’s qualifications to serve as a director include his 17 years of industry experience, prior work with Deloitte & Touche LLP and his former membership in the FASB’s Financial Accounting Standards Advisory Committee. Mr. Rogers also has community and public interest involvement and serves or has served on many non-profit foundations and boards.		2007

(1) Any service listed for Dominion and DRS reflects service at a parent, subsidiary or affiliate. Virginia Power is a wholly-owned subsidiary of Dominion. DRS is an affiliate of Virginia Power and is also a subsidiary of Dominion.

127

Executive Officers of Virginia Power

Information concerning the executive officers of Virginia Power, each of whom is elected annually, is as follows:

Name and Age	Business Experience Past Five Years(1)
Thomas F. Farrell II (58)	Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date.
Mark F. McGettrick (55)	Executive Vice President and CFO of Virginia Power and Dominion from June 2009 to date; President and COO-Generation of Virginia Power from February 2006 to May 2009; Executive Vice President of Dominion from April 2006 to May 2009.
Paul D. Koonce (53)	President and COO of Virginia Power from June 2009 to date; Executive Vice President and Chief Executive Officer-Energy Infrastructure Group of Dominion from February 2013 to date; Executive Vice President of Dominion from April 2006 to February 2013.
David A. Christian (58)	President and COO of Virginia Power from June 2009 to date; Executive Vice President and Chief Executive Officer-Dominion Generation Group of Dominion from February 2013 to date; Executive Vice President of Dominion from May 2011 to February 2013; President and CNO of Virginia Power from October 2007 to May 2009.
David A. Heacock (55)	President and CNO of Virginia Power from June 2009 to date; President and COO-DVP of Virginia Power and Senior Vice President of Dominion from June 2008 to May 2009; Senior Vice President-DVP of Virginia Power from October 2007 to May 2008.
Robert M. Blue (45)	Senior Vice President-Law, Public Policy and Environment of Virginia Power and Dominion from January 2011 to date; Senior Vice President-Public Policy and Environment of Dominion from February 2010 to December 2010; Senior Vice President-Public Policy and Corporate Communications of Dominion from May 2008 to January 2010; Vice President-State and Federal Affairs of DRS from September 2006 to May 2008.
Ashwini Sawhney (63)	Vice President-Accounting of Virginia Power from April 2006 to date; Vice President-Accounting and Controller (CAO) of Dominion from May 2010 to date; Vice President and Controller (CAO) of Dominion from July 2009 to May 2010; Vice President and Controller of Dominion from April 2007 to June 2009.

(1) Any service listed for Dominion and DRS reflects services at a parent, subsidiary or affiliate.

Section 16(a) Beneficial Ownership Reporting Compliance

To Virginia Power’s knowledge, for the fiscal year ended December 31, 2012, all Section 16(a) filing requirements applicable to its executive officers and directors were satisfied.

Audit Committee Financial Experts

Virginia Power is a wholly-owned subsidiary of Dominion. As permitted by SEC rules, its Board of Directors serves as Virginia Power’s Audit Committee and is comprised entirely of executive officers of Virginia Power or Dominion. Virginia Power’s Board of Directors has determined that Thomas F. Farrell II, Mark F. McGettrick and Steven A. Rogers are “audit committee financial experts” as defined by the SEC. As executive officers of Virginia Power and/or Dominion, Thomas F. Farrell II, Mark F. McGettrick and Steven A. Rogers were not deemed independent.

Code of Ethics

Virginia Power has adopted a Code of Ethics that applies to its principal executive, financial and accounting officers, as well as its employees. This Code of Ethics is the same as Dominion adopted and is available on the corporate governance section of Dominion’s website (www.dom.com). You may also request a copy of the Code of Ethics, free of charge, by writing or telephoning to: Corporate Secretary, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Any waivers or changes to Virginia Power’s Code of Ethics will be posted on the Dominion website.

Item 11. Executive Compensation

DOMINION

The following information about Dominion is contained in the 2013 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the headings Compensation Discussion and Analysis and Executive Compensation; the information regarding Compensation Committee interlocks contained under the heading Compensation Committee Interlocks and Insider Participation; the Compensation, Governance and Nominating Committee Report; and the information regarding director compensation contained under the heading Non-Employee Director Compensation.

VIRGINIA POWER

COMPENSATION COMMITTEE REPORT

In preparation for the filing of Virginia Power’s Annual Report on Form 10-K, Dominion’s CGN Committee reviewed and discussed the following CD&A with management and has recommended to the Board of Directors of Virginia Power that the CD&A be included in Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2012.

Robert S. Jepson, Jr., Chairman

William P. Barr

John W. Harris

Mark J. Kington

David A. Wollard

128

INTRODUCTION

Virginia Power is a wholly-owned subsidiary of Dominion. Virginia Power’s Board is comprised of Messrs. Farrell, McGettrick and Rogers. As executive officers of Virginia Power and/or Dominion, Messrs. Farrell, McGettrick and Rogers were not independent. Because Virginia Power’s Board is not independent, there is not a separate compensation committee at the Virginia Power level. Instead, Virginia Power’s Board depends on the advice and recommendations of Dominion’s CGN Committee which is comprised of independent directors. Virginia Power’s Board approves all compensation paid to Virginia Power’s executive officers based on Dominion’s CGN Committee recommendations.

None of Virginia Power’s directors receive any compensation for services they provide as directors of Virginia Power. No executive officer of Dominion or Virginia Power serves as a member of another compensation committee or on the Board of Directors of any company of which a member of Dominion’s CGN Committee, Dominion’s Board of Directors or Virginia Power’s Board of Directors serves as an executive officer.

Because the CGN Committee effectively administers one compensation program for all of Dominion, the following discussion and analysis is based on Dominion’s overall compensation program.

COMPENSATION DISCUSSION AND ANALYSIS

This CD&A provides a detailed explanation of the objectives and principles that underlie Dominion’s executive compensation program, its elements and the way performance is measured, evaluated and rewarded. It also describes Dominion’s compensation decision-making process. Dominion’s executive compensation program is designed to pay for performance and plays an important role in Dominion’s success by linking a significant amount of compensation to the achievement of performance goals.

The program and processes generally apply to all of Dominion’s officers, but this discussion and analysis focuses primarily on compensation for the NEOs of Virginia Power. During 2012, Virginia Power’s NEOs were:

Ÿ Thomas F. Farrell II, Chairman and CEO

Ÿ Mark F. McGettrick, Executive Vice President and CFO

Ÿ Paul D. Koonce, President and COO—DVP

Ÿ David A. Christian, President and COO—Generation

Ÿ David A. Heacock, President and CNO

The CGN Committee determines the compensation payable to officers of Dominion and its wholly-owned subsidiaries on an aggregate basis, taking into account all services performed by the officers, whether for Dominion or one or more of its subsidiaries. All of Virginia Power’s NEOs, except for Mr. Heacock, are NEOs of Dominion. For the NEOs included in Dominion’s annual proxy statement, these aggregate amounts are reported in the Summary Compensation Table and related executive compensation tables. For purposes of reporting each NEO’s compensation from Virginia Power in the Summary Compensation Table (and related tables that follow) in this Item 11, the aggregate compensation for each NEO is pro-rated based on the ratio of services performed by the NEO for Virginia Power to the NEO’s

total services performed for all of Dominion. For officers who are NEOs of both Virginia Power and Dominion, the amounts reported in the tables below are part of, and not in addition to the aggregate compensation amounts that are reported for these NEOs in Dominion’s 2013 Proxy Statement. The CD&A below discusses the CGN Committee’s decisions with respect to each NEO’s aggregate compensation for all services performed for all of Dominion, not just the pro-rated portion attributable to the NEO’s services for Virginia Power.

OBJECTIVES OF DOMINION’S EXECUTIVE COMPENSATION PROGRAM AND THE COMPENSATION DECISION-MAKING PROCESS

Objectives

Dominion’s executive compensation philosophy is to provide a competitive total compensation program tied to performance and aligned with the interests of Dominion shareholders, employees and customers.

The major objectives of Dominion’s compensation program are to:

Ÿ Attract, develop and retain an experienced and highly qualified management team;

Ÿ Motivate and reward superior performance that supports Dominion’s business and strategic plans and contributes to the long-term success of the company;

Ÿ Align the interests of management with those of Dominion’s shareholders and customers by placing a substantial portion of pay at risk through performance goals that, if achieved, are expected to increase TSR and enhance customer service;

Ÿ Promote internal pay equity; and

Ÿ Reinforce Dominion’s four core values of safety, ethics, excellence and One Dominion—Dominion’s term for teamwork.

These objectives provide the framework for the compensation decisions. To determine if Dominion is meeting the objectives of its compensation program, the CGN Committee reviews and compares Dominion’s actual performance to its short-term and long-term goals, strategies, and peer companies’ performance.

Dominion’s 2012 performance indicates that the design of Dominion’s compensation program is meeting these objectives. The NEOs have service with Dominion ranging from 14 to 36 years. Dominion has attracted, motivated and maintained a superior leadership team with skills, industry knowledge and institutional experience that strengthen their ability to act as sound stewards of Dominion’s shareholder dollars. Dominion is performing well relative to internal goals and as compared to its peers.

In 2012, Dominion shareholders voted on the executive compensation program (also known as “Say on Pay”) and approved it on an advisory basis by almost 95%, which followed approval of 94% in the prior year. The CGN Committee considered the very strong shareholder endorsement of the CGN Committee’s decisions and policies and Dominion’s overall executive compensation program in continuing the pay-for-performance program that is currently in place without any specific changes for 2013 based on the vote. Unless Dominion’s

129

Board of Directors modifies its policy on the frequency of future Say-on-Pay advisory votes, shareholders will have an opportunity annually to cast an advisory vote in connection with executive compensation. Dominion will ask shareholders, on an advisory basis, to vote on the frequency of the Say-on-Pay vote at least once every six years, with the next advisory vote on frequency to be held no later than Dominion’s 2017 Annual Meeting of Shareholders.

The Process for Setting Compensation

The CGN Committee is responsible for reviewing and approving NEO compensation and the overall executive compensation program. Each year, the CGN Committee reviews and considers a comprehensive assessment and analysis of the executive compensation program, including the elements of each NEO’s compensation, with input from management and the independent compensation consultant. As part of its assessment, the CGN Committee reviews the performance of the CEO and other executive officers, meets at least annually with the CEO to discuss succession planning for his position and the positions of Dominion’s senior officers, reviews the share ownership guidelines and executive officer compliance with the guidelines, and establishes compensation programs designed to achieve Dominion’s objectives.

THE ROLE OF THE INDEPENDENT COMPENSATION CONSULTANT

The CGN Committee has retained an independent compensation consultant, PM&P, to advise the committee on executive and director compensation matters. The PM&P consultant participates in meetings with the CGN Committee, either in person or by teleconference, and communicates directly with the chairman of the committee outside of the committee meetings as requested by the chairman of the committee. PM&P also reviewed meeting materials as requested for the CGN Committee and provided the following services related to the 2012 executive compensation program:

Ÿ Participated in CGN Committee executive sessions without management present to discuss CEO compensation and any other relevant matters, including the appropriate relationship between pay and performance and emerging trends, to answer technical questions, and to review and comment on management proposals; and

Ÿ Generally reviewed and offered advice as requested by or on behalf of the CGN Committee regarding other aspects of the executive compensation program, including best practices and other matters.

PM&P received compensation from Dominion for consulting services related only to executive and director compensation, except for $3,300 related to Dominion’s participation in one natural gas transmission compensation survey which was administered by PM&P. PM&P did not provide any additional services to Dominion.

The CGN Committee has reviewed and considered information provided to the CGN Committee by its PM&P consultant, the CGN Committee members and Dominion’s executive officers, and based on its review and such factors as it deemed relevant, the CGN Committee has concluded that the advice it receives from PM&P is objective and that PM&P’s work did not raise any conflict of interest.

MANAGEMENT’S ROLE IN DOMINION’S PROCESS

Although the CGN Committee has the responsibility to approve and monitor all compensation for the NEOs, management plays an important role in determining executive compensation. Under the direction of the Corporate Secretary, internal compensation specialists provide the CGN Committee with data, analysis and counsel regarding the executive compensation program, including an ongoing assessment of the effectiveness of the program, peer practices, and executive compensation trends and best practices. The CEO, CFO and Corporate Secretary, along with the internal compensation and financial specialists, assist in the design of the incentive compensation plans, including performance target recommendations consistent with the strategic goals of the company, and recommendations for establishing the peer group. Management also works with the Chairman of the CGN Committee to establish the agenda and prepare meeting information for each CGN Committee meeting.

As discussed previously, the CEO is responsible for reviewing senior officer succession plans with the CGN Committee on an annual basis. He is also responsible for reviewing the performance of his senior officers, including the other NEOs, with the CGN Committee at least annually. He makes recommendations on the compensation and benefits for the NEOs (other than himself) to the CGN Committee and provides other information and counsel as appropriate or as requested by the CGN Committee, but all decisions are ultimately made by the CGN Committee.

THE COMPENSATION PEER GROUP

The CGN Committee uses two peer groups for executive compensation. The Compensation Peer Group is used to assess the competitiveness of the compensation of the NEOs. Starting with the 2012 Performance Grant, a separate Performance Grant Peer Group is used to evaluate the relative performance of Dominion for purposes of the LTIP. (See 2012 Performance Grants for additional information.) In the fall of each year, the CGN Committee approves a Compensation Peer Group of companies. In selecting the Compensation Peer Group, Dominion uses a methodology generally recommended by PM&P to identify companies in the industry that compete for customers, executive talent and investment capital. Dominion screens this group based on size and usually eliminates companies that are much smaller or larger than Dominion’s size in revenues, assets and market capitalization. Dominion also considers the geographic locations and the regulatory environment in which potential peer companies operate.

Dominion’s Compensation Peer Group is generally consistent from year to year, with merger and acquisition activity being the primary reason for any changes. No changes were made to the peer group used for setting compensation for 2012. The members of Dominion’s Compensation Peer Group are as follows:

Ameren Corporation	FirstEnergy Corp.
American Electric Power Company, Inc. CMS Energy Corporation DTE Energy Company Duke Energy Corporation	NextEra Energy, Inc. NiSource, Inc. PPL Corporation Public Service Enterprise Group Inc.
Entergy Corporation Exelon Corporation	The Southern Company Xcel Energy Inc.

130

The CGN Committee and management use data from the Compensation Peer Group prepared by management to: (i) compare Dominion’s stock and financial performance against its peers using a number of different metrics and time periods to evaluate how Dominion is performing as compared to its peers; (ii) analyze compensation practices within the industry; (iii) evaluate peer company practices and determine peer median and 75th percentile ranges for base pay, annual incentive pay, long-term incentive pay and total direct compensation, both generally and for specific positions; and (iv) compare benefits and perquisites. In setting the levels for base pay, annual incentive pay, long-term incentive pay and total direct compensation, the CGN Committee also takes into consideration Dominion’s larger size compared with the median of the Compensation Peer Group.

SURVEY DATA

Dominion did not benchmark or otherwise use broad-based market data as the basis for compensation decisions for the NEOs. Survey compensation data is used only to provide a general understanding of compensation practices and trends. The CGN Committee takes into account individual and company specific factors, including internal pay equity, along with data from the Compensation Peer Group in establishing compensation opportunities. The CGN Committee believes that this emphasis better reflects Dominion’s specific needs in its distinct competitive market and with respect to its size and complexity versus its peers.

COMPENSATION DESIGN AND RISK

Dominion’s management, including Dominion’s chief risk officer and other executives, annually reviews the overall structure of Dominion’s executive compensation program and policies to ensure they are consistent with effective management of enterprise key risks and that they do not encourage executives to take unnecessary or excessive risks that could threaten the value of the enterprise. With respect to the programs and policies that apply to the NEOs, this review includes:

Ÿ Analysis of how different elements of the compensation programs may increase or mitigate risk-taking;

Ÿ Analysis of performance metrics used for short-term and long-term incentive programs and the relation of such incentives to the objectives of Dominion;

Ÿ Analysis of whether the performance measurement periods for short-term and long-term incentive compensation are appropriate; and

Ÿ Analysis of the overall structure of compensation programs as related to business risks.

Among the factors considered in management’s assessment are: the balance of the overall program design, including the mix of cash and equity compensation; the mix of fixed and variable compensation; the balance of short-term and long-term objectives of incentive compensation; the performance metrics, performance targets, threshold performance requirements and capped payouts related to incentive compensation; the clawback provision on incentive compensation; Dominion’s share ownership guidelines, including share ownership levels and retention practices; prohibitions on hedging, pledging, and other derivative transactions related to Dominion stock; and internal controls and oversight structures in place at Dominion.

Management reviewed and provided the results of this assessment to the CGN Committee. Based on this review, the CGN Committee believes that Dominion’s well-balanced mix of salary and short-term and long-term incentives, as well as the performance metrics that are included in the incentive programs, are appropriate and consistent with Dominion’s risk management practices and overall strategies.

OTHER TOOLS

The CGN Committee uses a number of tools in its annual review of the compensation of Dominion’s CEO and other NEOs, including charts illustrating the total range of payouts for each performance-based compensation element under a number of different scenarios; spreadsheets showing the cumulative dollar impact on total direct compensation that could result from implementing proposals on any single element of compensation; graphs showing the relationship between the CEO’s pay and that of the next highest-paid officer and Dominion’s NEOs as a group; and other information the CGN Committee may request in its discretion. Management’s internal compensation specialists provide the CGN Committee with detailed comparisons of the design and features of Dominion’s long-term incentive and other executive benefit programs with available information regarding similar programs at the companies in the Compensation Peer Group. These tools are used as part of the overall process to ensure that the program results in appropriate pay relationships as compared to Dominion’s peer companies and internally among Dominion’s NEOs, and that an appropriate balance of at-risk, performance-based compensation is maintained to support the program’s core objectives. No material adjustments were made to Dominion’s NEO’s compensation as a result of using these tools.

131

ELEMENTS OF DOMINION’S COMPENSATION PROGRAM

The executive compensation program consists of four basic elements:

Pay Element	Primary Objectives	Key Features & Behavioral Focus
Base Salary	Ÿ      Provide competitive level of fixed cash compensation for performing day-to-day responsibilities Ÿ       Attract and retain talent	Ÿ      Generally targeted at or slightly above peer median, with individual and company-wide considerations Ÿ       Rewards individual performance and level of experience
Annual Incentive Plan	Ÿ      Provide competitive level of at-risk cash compensation for achievement of short-term financial and operational goals Ÿ       Align short-term compensation with annual budget, earnings goals, business plans and core values	Ÿ      Cash payments based on achievement of annual financial and individual operating and stewardship goals Ÿ       Rewards achievement of annual financial goals for Dominion as well as business unit and individual goals selected to support longer-term strategies
Long-Term Incentive Program	Ÿ      Provide competitive level of at-risk compensation for achievement of long-term performance goals Ÿ       Create long-term shareholder value Ÿ       Retain talent and support the succession planning process	Ÿ      A combination of performance-based cash and restricted stock awards Ÿ      Encourages and rewards officers for making decisions and investments that create long-term shareholder value as reflected in superior relative total shareholder returns, as well as achieving desired ROIC
Employee and Executive Benefits	Ÿ      Provide competitive retirement and other benefit programs that attract and retain highly qualified individuals Ÿ       Provide competitive terms to encourage officers to remain with Dominion during any potential change in control to ensure an orderly transition of management	Ÿ      Includes company-wide benefit programs, executive retirement plans, limited perquisites, and change in control and other agreements, supplemented with non-compete provisions in the non-qualified retirement plans Ÿ       Encourages officers to remain with Dominion long-term and to act in the best interests of shareholders, even during any potential change in control

Factors in Setting Compensation

As part of the process of setting compensation targets, approving payouts and designing future programs, the CGN Committee evaluates Dominion’s overall performance versus its business plans and strategies, its short-term and long-term goals and the performance of its peer companies. In addition to considering Dominion’s overall performance for the year, the CGN Committee takes into consideration several individual factors that are not given any specific weighting in setting each element of compensation for each NEO, including:

Ÿ An officer’s experience and job performance;

Ÿ The scope, complexity and significance of responsibility for a position, including any differences from peer company positions;

Ÿ Internal pay equity considerations, such as the relative importance of a particular position or individual officer to Dominion’s strategy and success, and comparability to other officer positions at Dominion;

Ÿ Retention and market competitive concerns; and

Ÿ The officer’s role in any succession plan for other key positions.

The CGN Committee evaluates each NEO’s base salary, total cash and total direct compensation opportunities against data from the Compensation Peer Group to ensure the compensation levels are appropriately competitive, but does not target these compensation levels at a particular percentile or range of the peer group data. For Mr. Heacock, the same evaluation process is performed using the Towers Watson Energy Services data instead of peer group data. See Exhibit 99.3 for a listing of the companies included in the survey. As part of this analysis, the CGN Committee also takes into account Dominion’s larger size and complexity compared to the companies in the Compensation Peer Group.

In setting compensation for 2012, Dominion provided a modest increase in base salary for all officers, including all NEOs, and made adjustments to performance-based compensation target levels for certain officers. Based on the review of data from the Compensation Peer Group, each NEO’s job performance, recent promotions and internal pay equity considerations such as scope and complexity of the position relative to other positions at Dominion, the CGN Committee determined it was appropriate to increase the target levels under the 2012 AIP for Mr. Christian as described below in Annual Incentive Plan and the LTIP for Messrs. McGettrick, Christian and Koonce as described below in Long-Term Incentive Program.

CEO Compensation Relative to Other NEOs

Mr. Farrell participates in the same compensation programs and receives compensation based on the same philosophy and factors as other NEOs. Application of the same philosophy and factors to Mr. Farrell’s position results in overall CEO compensation that is significantly higher than the compensation of the other NEOs. His compensation is commensurate with his greater responsibilities and decision-making authority, broader scope of duties encompassing the entirety of Dominion (as compared to the other NEOs who are responsible for significant but distinct areas within Dominion) and his overall responsibility for corporate strategy. His compensation also reflects his role as the principal corporate representative to investors, customers, regulators, analysts, legislators, industry and the media.

Dominion considers CEO compensation trends as compared to the next highest-paid officer, as well as to other executive officers as a group, over a multi-year period to monitor the ratio of Mr. Farrell’s pay relative to the pay of other executive officers based on (i) salary only and (ii) total direct compensation. Dominion also compares its ratios to that of its peers to confirm

132

that its ratios are consistent with practices at the peer companies. There is no particular targeted ratio or goal, but instead the CGN Committee considers year-to-year trends and comparisons with peer companies. The CGN Committee did not make any adjustments to the compensation of any NEOs based on this review in 2012.

Allocation of Total Direct Compensation in 2012

Consistent with Dominion’s objective to reward strong performance based on the achievement of short-term and long-term goals, a significant portion of total cash and total direct compensation is at risk. Total direct compensation is the sum of base salary, targeted AIP compensation and targeted long-term incentive compensation. Approximately 87% of Mr. Farrell’s targeted 2012 total direct compensation is performance-based, tied to pre-approved performance metrics, including relative TSR and ROIC, or tied to the performance of Dominion’s stock. For the other NEOs, performance-based and stock-based compensation ranges from 65% to 80% of targeted 2012 total direct compensation. This compares to an average of approximately 52% of targeted compensation at risk for most officers at the vice president level and an average of approximately 12% of total pay at risk for non-officer employees.

The charts below illustrate the elements of total direct compensation opportunities in 2012 for Mr. Farrell and the average of the other NEOs as a group and the allocation of such compensation among base salary, targeted 2012 AIP award and targeted 2012 long-term incentive compensation.

Base Salary

Base salary compensates officers, along with the rest of the workforce, for committing significant time to working on Dominion’s

behalf. Annual salary reviews achieve two primary purposes: (i) an annual adjustment, as appropriate, to keep salaries in line and competitive with the Compensation Peer Group and to reflect changes in responsibility, including promotions; and (ii) a motivational tool to acknowledge and reward excellent individual performance, special skills, experience, the strategic impact of a position relative to other Dominion executives and other relevant considerations.

The primary goal is to compensate officers at a level that best achieves Dominion’s objectives and reflects the considerations discussed above. Dominion believes that an overall goal of targeting base salary at or slightly above the Compensation Peer Group median is a conservative but appropriate target for base pay. However, an individual’s compensation may be below or above Dominion’s target range based on a number of factors such as performance, tenure, and other factors explained above in Factors in Setting Compensation. In addition to being ranked above or at the Compensation Peer Group median in 2012 in terms of revenues, assets and market capitalization, the scope of Dominion’s business operations is complex and unique in its industry. Successfully managing such a broad and complex business requires a skilled and experienced management team. Dominion believes it would not be able to successfully recruit and retain such a team if the base pay for officers was generally below the Compensation Peer Group median. For 2012, the CGN Committee approved a 7.5% base salary increase for Messrs. Farrell and Christian, a 3% base salary increase for Messrs. McGettrick and Koonce and a 4% base salary increase for Mr. Heacock. In determining the base salary increase for Mr. Farrell, the CGN Committee considered Dominion’s strong performance in 2011 as well as Mr. Farrell’s individual performance, the complexity of Dominion and the energy industry itself and Mr. Farrell’s leadership in the industry and other factors. For Mr. Christian, the CGN Committee took into consideration that Mr. Christian’s base salary was slightly below the Compensation Peer Group median, the increased competitiveness for nuclear industry expertise and the size of the Dominion Generation business unit, which is the largest of Dominion’s three business units, relative to Dominion’s other business units and other factors. Effective January 1, 2013, the CGN Committee increased Mr. Koonce’s base salary 10% to recognize his increased responsibility as CEO of the Energy Infrastructure Group with the CEO of the Dominion Energy business unit reporting to him.

Annual Incentive Plan

OVERVIEW

The AIP plays an important role in meeting Dominion’s overall objective of rewarding strong performance. The AIP is a cash-based program focused on short-term goal accomplishments and is designed to:

Ÿ Tie interests of shareholders, customers and employees closely together;

Ÿ Focus the workforce on company, operating group, team and individual goals that ultimately influence operational and financial results;

Ÿ Reward corporate and operating unit earnings performance;

Ÿ Reward safety and other operating and stewardship goal successes;

133

Ÿ Emphasize teamwork by focusing on common goals;

Ÿ Appropriately balance risk and reward; and

Ÿ Provide a competitive total compensation opportunity.

TARGET AWARDS

An NEO’s compensation opportunity under the AIP is based on a target award. Target awards are determined as a percentage of a participant’s base salary (for example, 85% of base salary). The target award is the amount of cash that will be paid if the plan is funded at the full funding target set for the year and a participant achieves a score of 100% for the payout goals. Participants who retire during the plan year are eligible to receive a prorated payment of their AIP award after the end of the plan year based on final funding and goal achievement. Participants who voluntarily terminate employment during the plan year and who are not eligible to retire (before attainment of age 55) forfeit their AIP award.

AIP target award levels are established based on a number of factors, including historical practice, individual and company performance and internal pay equity considerations, and are compared against Compensation Peer Group data to ensure the appropriate competitiveness of an NEO’s total cash compensation opportunity. However, as discussed above, AIP target award levels were not targeted at a specific percentile or range of the peer group data, nor was market survey data used in setting AIP target award levels for 2012. Annual incentive target award levels are also consistent with Dominion’s intent to have a significant portion of NEO compensation at risk. For 2012, Mr. Christian’s AIP target award percentage was increased from 85% to 90% of base salary to reflect the continued transition of his compensation to a business unit CEO level. There were no changes to the AIP targets as a percentage of salary for Messrs. Farrell, McGettrick, Koonce and Heacock for 2012.

Name	2011 AIP Target Award*		2012 AIP Target Award*
Thomas F. Farrell II		125%		125%
Mark F. McGettrick		100%		100%
David A. Christian		85%		90%
Paul D. Koonce		90%		90%
David A. Heacock		70%		70%

* As a % of base salary

FUNDING OF THE 2012 AIP

Funding of the 2012 AIP was based solely on consolidated operating earnings per share, with potential funding ranging from 0% to 200% of the target funding. Consolidated operating earnings are Dominion’s reported earnings determined in accordance with GAAP, adjusted for certain items. Dominion believes that by placing a focus on pre-established consolidated operating earnings per share targets, it increases employee awareness of the company’s financial objectives and encourages behavior and performance that will help achieve these objectives.

For the 2012 AIP, the CGN Committee established a full funding target at 100% for the NEOs at $3.05 operating earnings per share, inclusive of funding for all plan participants. The maximum funding target of 200% was set at $3.15 operating earnings per share, and no funding if operating earnings were less than $3.05 per share (threshold), with the Committee retaining negative discretion to determine the final funding level.

Full funding means that the AIP is 100% funded and participants can receive their full targeted AIP payout if they achieve a score of 100% for their particular goal package, as described below in How AIP Payouts Are Determined. At the maximum

plan funding level of 200%, participants can earn up to two times their targeted AIP payout, subject to achievement of their individual goal packages.

Dominion’s consolidated operating earnings for the year ended December 31, 2012 were $1.75 billion or $3.05 per share, as compared to its consolidated reported earnings in accordance with GAAP of $302 million or $0.53 per share, with enough earnings above $3.05 (before AIP funding) to support 60% funding for the 2012 AIP.*

*Reconciliation of 2012 Consolidated Operating Earnings to Reported Earnings. The following items, which are net of tax, are included in Dominion’s 2012 reported earnings, but are excluded from consolidated operating earnings: $1.1 billion net loss, including an impairment charge, associated with certain fossil fuel-fired merchant power stations that Dominion decided to market for sale in the third quarter of 2012; $303 million net loss, including impairment charges, primarily resulting from the planned shutdown of the Kewaunee nuclear merchant power station; $53 million of restoration costs associated with severe storms affecting the Dominion Virginia Power and Dominion North Carolina Power service territories; $22 million net loss from discontinued operations of two merchant power stations (State Line and Salem Harbor) that were sold in 2012; and $5 million net benefit related to other items.

HOW AIP PAYOUTS ARE DETERMINED

For Dominion’s NEOs, payout of funded AIP awards is contingent solely on the achievement of the consolidated operating financial goal with the CGN Committee retaining negative discretion to lower the payout as it deems appropriate, taking into consideration the accomplishment of the consolidated financial, business unit financial and operating and stewardship goals, including a safety goal. The percentage allocated to each category of goals represents the percentage of the funded award subject to the performance of that goal. Officer goals are weighted according to their responsibilities. The overall score cannot exceed 100%.

Business unit financial goals provide a line-of-sight performance target for officers within a business unit and, on a combined basis, support the consolidated operating earnings target for Dominion. Operating and stewardship goals provide line-of-sight performance targets that may not be financial and that can be customized for each individual or by segments of each business unit. Operating and stewardship goals promote the core values of safety, ethics, excellence and teamwork, which in turn contribute to Dominion’s financial success.

The discretionary payout goals adopted by each NEO are described under 2012 AIP Payouts and the weightings applied to those goals are shown in the table below.

Name	Consolidated Financial Goal		Business Unit Financial Goals		Operating/ Stewardship Goals*
Thomas F. Farrell II		95%		—		5%
Mark F. McGettrick		95%		—		5%
David A. Christian		65%		30%		5%
Paul D. Koonce		65%		30%		5%
David A. Heacock		40%		30%		30%

*5% goal weighting is for safety goal. Mr. Heacock had other non-safety operating and stewardship goals as described below.

134

2012 AIP PAYOUTS

The formula for calculating an award is:

The consolidated financial goal was consolidated operating earnings for the year ended December 31, 2012 of $3.05 per share, which was accomplished as described above. The 2012 business unit financial goals and accomplishment levels for Mr. Koonce (DVP), and Messrs. Christian and Heacock (Dominion Generation) were as follows:

Business Unit	Goal Threshold (Net Income)		Goal 100% Payout (Net Income)		Actual 2012 Net Income		2012 Approved Accomplishment
(Million/$)
DVP	$	431	$	539	$	559		100%
Dominion Generation		803		1,004		874		87

Messrs. Farrell and McGettrick each received partial credit for their safety goal as the DRS business unit had five OSHA recordable incidents which exceeded the target of four or less OSHA recordable incidents with an incidence rate of 0.15 or less. Mr. Christian met his target safety goal of an OSHA incidence rate ranging from 0.16 to 1.31 for certain operating units and recordable incidents of two or fewer for another operating unit in the Dominion Generation business unit. Mr. Koonce met his target safety goal of an OSHA incidence rate of 1.39 and lost time/restricted duty rate of 0.25 for the DVP business unit. Mr. Heacock met his target safety goal of less than seven fleetwide total OSHA recordable injuries (weighted 6%) and his nuclear safety goal of less than six station clock resets for total nuclear fleet (weighted 8%). In addition to his safety goal, Mr. Heacock had operating and stewardship goals in three other categories: environmental compliance (weighted 5%); radiation exposure (weighted 4%); and fleet capacity factor (weighted 7%), Mr. Heacock met all three of these goals.

The CGN Committee exercised negative discretion to lower the payouts for Messrs. Farrell and McGettrick due to their missed safety goals and Messrs. Christian and Heacock due to their missed business unit financial goals. Amounts earned under the 2012 AIP by NEOs are shown below and are reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

Name	Base Salary			Target Award*			Funding%			Total Payout Score %			2012 AIP Payout
Thomas F. Farrell II	$	386,319	X		125%	X		60%	X		99%	=	$	286,842
Mark F. McGettrick		313,402	X		100%	X		60%	X		99%	=		186,161
David A. Christian		327,668	X		90%	X		60%	X		96%	=		169,863
Paul D. Koonce		431,709	X		90%	X		60%	X		100%	=		233,123
David A. Heacock		207,766	X		70%	X		60%	X		96%	=		83,771

*As a % of base salary.

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.

Messrs. Farrell and McGettrick’s payout scores were calculated as follows:

Name	Consolidated Financial Goal Accomplishment			Goal Weighting			Operating/ Stewardship Goal Accomplishment			Goal Weighting			Total Payout Score
Thomas F. Farrell II		100%	X		95%	+		80%	X		5%	=		99	%
Mark F. McGettrick		100%	X		95%	+		80%	X		5%	=		99	%

Messrs. Christian, Koonce and Heacock’s payout scores were calculated as follows:

Name	Consolidated Financial Goal Accomplishment			Goal Weighting			Business Unit Financial Goal Accomplishment			Goal Weighting			Operating/ Stewardship Goal Accomplishment			Goal Weighting			Total Payout Score
David A. Christian		100%	X		65%	+		87%	X		30%	+		100%	X		5%	=		96%
Paul D. Koonce		100%	X		65%	+		100%	X		30%	+		100%	X		5%	=		100%
David A. Heacock		100%	X		40%	+		87%	X		30%	+		100%	X		30%	=		96%

135

Long-Term Incentive Program

OVERVIEW

Dominion’s LTIP focuses on Dominion’s longer-term strategic goals and retention of its executives. Since 2006, 50% of Dominion’s long-term incentives have been full value equity awards in the form of restricted stock with time-based vesting and the other 50% have been performance-based awards. Dominion believes restricted stock serves as a strong retention tool and also creates a focus on Dominion’s stock price to further align the interests of officers with the interests of its shareholders and customers. For those officers who have made substantial progress toward their share ownership guidelines, the performance-based award is in the form of a cash performance grant. Officers who have not achieved 50% of their targeted share ownership guideline receive goal-based stock performance grants instead of a cash performance grant. Dividend equivalents are not paid on any performance-based grants. Because officers are expected to retain ownership of shares upon vesting of restricted stock awards, as explained in Share Ownership Guidelines, the long-term cash performance grant balances the program and allows a portion of the long-term incentive award to be accessible to the NEOs during the course of their employment. As all of the NEOs have satisfied their full targeted share ownership, all of the NEOs received the performance-based component of their 2012 long-term incentive award in the form of a cash performance grant.

The CGN Committee approves long-term incentive awards in January each year with a grant date established in early February. This process ensures incentive-based awards are made at the beginning of the performance period and shortly after the public disclosure of Dominion’s earnings for the prior year. Like the AIP target award levels discussed above, long-term incentive target award levels were established based on a number of factors, including historical practice, individual and company performance, and internal pay equity considerations, and are compared against Compensation Peer Group data to ensure the appropriate competitiveness of an NEO’s total direct compensation opportunity. However, as discussed above, long-term incentive target award levels are not targeted at a specific percentile or range of the Compensation Peer Group data, nor was market survey data a factor in setting long-term incentive target award levels for 2012.

For 2012, the CGN Committee approved increases to the target long-term incentive awards for Messrs. McGettrick, Christian and Koonce as discussed below. There was no change to the target long-term incentive award for Mr. Farrell or for Mr. Heacock.

MCGETTRICK. Among the factors considered by the CGN Committee in determining the amount of Mr. McGettrick’s award were Mr. McGettrick’s continued superior performance as CFO and his broad-based experience. The CGN Committee determined it was appropriate to approve a 6% increase in Mr. McGettrick’s target long-term incentive award, which resulted in a 5% increase in total direct compensation at target.

CHRISTIAN. For Mr. Christian’s target long-term incentive award, the CGN Committee considered, among other factors, Mr. Christian’s performance as CEO of the Dominion Generation business unit and his experience with the company. The CGN Committee also considered the size of the Dominion Generation business unit, which is the largest of Dominion’s three

business units, relative to Dominion’s other business units in determining his target long-term incentive award, the continued transition of Mr. Christian’s compensation to a business unit CEO level and the increased industry competitiveness for personnel with nuclear expertise. The CGN Committee determined it was appropriate to approve an 18% increase in Mr. Christian’s target long-term incentive award, which resulted in a 14% increase in total direct compensation at target.

KOONCE. Among the factors considered by the CGN Committee in determining the amount of Mr. Koonce’s award were Mr. Koonce’s performance as CEO of the DVP business unit and his experience and long tenure with Dominion. The CGN Committee determined it was appropriate to approve a 13% increase in Mr. Koonce’s target long-term incentive award, which resulted in a 9% increase in total direct compensation at target.

Information regarding the fair value of the 2012 restricted stock grants and target cash performance grants for the NEOs is provided in the Grants of Plan-Based Awards table.

2012 RESTRICTED STOCK GRANTS

All officers received a restricted stock grant on February 1, 2012 based on a stated dollar value. The number of shares awarded was determined by dividing the stated dollar value by the closing price of Dominion’s common stock on February 1, 2012. The grants have a three-year vesting term, with cliff vesting at the end of the restricted period on February 1, 2015. Dividends are paid to officers during the restricted period. The grant date fair value and vesting terms of the 2012 restricted stock grant awards made to the NEOs are disclosed in the Grants of Plan-Based Awards table and related footnotes.

2012 PERFORMANCE GRANTS

In January 2012, the CGN Committee approved cash performance grants for the NEOs, effective February 1, 2012. The performance period commenced on January 1, 2012 and will end on December 31, 2013. The 2012 grants are denominated as a target award, with potential payouts ranging from 0-200% of the target based on Dominion’s TSR relative to a Performance Grant Peer Group of companies selected by the CGN Committee and ROIC, weighted equally.

The TSR metric was selected to focus officers on long-term shareholder value when developing and implementing their strategic plans and in turn, reward management based on the achievement of TSR levels as measured relative to Dominion’s peer companies. The ROIC metric was selected to reward officers for the achievement of expected levels of return on Dominion’s investments. Dominion believes an ROIC measure encourages management to choose the right investments, and with those investments, to achieve the highest returns possible through prudent decisions, management and control of costs. The target awards and vesting terms of 2012 performance grants made to the NEOs are disclosed in the Grants of Plan-Based Awards table and related footnotes.

136

Performance Grant Peer Group

Since performance grants were first awarded in 2006, Dominion’s TSR performance has been measured relative to a Performance Grant Peer Group that included the same companies included in its peer group for compensation setting purposes.

For the 2011 Performance Grant, the peer group used in measuring relative TSR is the same group of companies included in the Compensation Peer Group, excluding Constellation and Progress Energy due to their mergers with Exelon and Duke, respectively (2011 Performance Grant Peer Group). Following its annual review of the design of the LTIP, the CGN Committee approved measuring TSR performance for the 2012 Performance Grant against the TSR of the companies listed as members of the Philadelphia Stock Exchange Utility Index at the end of the performance period (2012 Performance Grant Peer Group). In selecting the Philadelphia Utility Index, the CGN Committee took into consideration that the companies represented in the Philadelphia Stock Exchange Utility Index are similar to those companies currently included in Dominion’s Compensation Peer Group and the index itself is a recognized published index whose members are determined externally and independently from Dominion. The CGN Committee also took into consideration the past and recent mergers within the utility industry and the effects of consolidation on the size of Dominion’s Performance Grant Peer Group. The companies in the Philadelphia Stock Exchange Utility Index at the grant date of the 2012 Performance Grant were as follows:

The AES Corporation Ameren Corporation American Electric Power Company, Inc. CenterPoint Energy, Inc. Consolidated Edison, Inc. Covanta Holding Corporation DTE Energy Company Duke Energy Corporation Edison International El Paso Electric Company Entergy Corporation Exelon Corporation FirstEnergy Corp. NextEra Energy, Inc. Northeast Utilities PG&E Corporation Public Service Enterprise Group Incorporated The Southern Company Xcel Energy Inc.

For 2012 Performance Grants, the CGN Committee also approved recalibrating the performance grant payout scale for the TSR metric so that payout will be capped at 200% at the 85th percentile of the Performance Grant Peer Group rather than at the 100th percentile, which is consistent with the long-term incentive plans of several companies in Dominion’s Compensation Peer Group. No other changes were made to the payout scale with payout at target (or 100%) remaining at the 50th percentile of the Performance Grant Peer Group, payout at threshold (or 50%) at the 25th percentile and no payout for relative TSR below the 25th percentile.

PAYOUT UNDER 2011 PERFORMANCE GRANTS

In February 2013, final payouts were made to officers who received 2011 performance grants, including the NEOs. The 2011 performance grants were based on two goals: TSR for the two-year period ended December 31, 2012 relative to Dominion’s 2011 Performance Peer Group (weighted 50%) and ROIC for the same two-year period (weighted 50%).

Ÿ Relative TSR (50% weighting). TSR is the difference between the value of a share of common stock at the beginning and

end of the two-year performance period, plus dividends paid as if reinvested in stock. For this metric, Dominion’s TSR is compared to TSR levels of the companies in the 2011 Performance Grant Peer Group for the same two-year period. The relative TSR targets and corresponding payout scores for the 2011 performance grant are as follows:

Relative TSR Performance	Percentage Payout of TSR Percentage*
1st Quartile – 75% to 100%	150% – 200%
2nd Quartile – 50% to 74.9%	100% – 149.9%
3rd Quartile – 25% to 49.9%	50% – 99.9%
4th Quartile – below 25%	0%

*TSR weighting is interpolated between the top and bottom of the percentages within a quartile. A minimum payment of 25% of the TSR percentage will be made if the TSR performance is at least 10% on a compounded annual basis for the performance period, regardless of relative performance.

Actual relative TSR performance for the 2011-2012 period was in the second quartile. Dominion’s TSR for the two-year period ended December 31, 2012 was 31.6%, which ranked sixth relative to the peer group which was comprised of the same companies in the Compensation Peer Group and placed Dominion ahead of nine of the 14 peer companies.

Ÿ ROIC (50% weighting). ROIC reflects Dominion’s total return divided by average invested capital for the performance period. The ROIC goal at target is consistent with the strategic plan/annual business plan as approved by Dominion’s Board. For this purpose, total return is Dominion’s consolidated operating earnings plus its after-tax interest and related charges, plus preferred dividends. Dominion designed its 2011 ROIC goals to provide 100% payout if it achieved an average ROIC of 7.60% over the two-year performance period. The ROIC performance targets and corresponding payout scores are as follows:

ROIC Performance	Percentage Payout of ROIC Percentage*
7.88% and above		200%
7.74% – 7.87%		150% – 199.9%
7.60% – 7.73%		100% – 149.9%
7.46% – 7.59%		50% – 99.9%
Below 7. 46%		0%

*ROIC percentage payout is interpolated between the top and bottom of the percentages for any range.

Actual ROIC performance for the 2011-2012 period was 7.40% which produced a payout of 0%.

Based on the achievement of the performance criteria, the CGN Committee approved a 64.2% payout for the 2011 performance grants. The following table summarizes the achievement of the 2011 performance criteria:

Measure	Goal Weight%			Goal Achievement%			Payout%
Relative TSR		50%	X		128.5%	=		64.2%
ROIC		50%	X		0%	=		0%
Combined Overall Performance Score								64.2%

137

The resulting payout amounts for the NEOs for the 2011 performance grants are shown below and are also reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

Name	2011 Performance Grant Award			Overall Performance Score			Calculated Performance Grant Payout
Thomas F. Farrell II	$	1,027,600	X		64.2%	=	$	659,719
Mark F. McGettrick		458,300	X		64.2%	=		294,229
David A. Christian		303,525	X		64.2%	=		194,863
Paul D. Koonce		464,231	X		64.2%	=		298,036
David A. Heacock		117,650	X		64.2%	=		75,531

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.

Other Restricted Stock Grants

The CGN Committee may consider other restricted stock grants for selected individuals in order to support key objectives including succession planning, talent retention and recruitment. These awards are not considered part of the annual program and are only awarded periodically. In December 2012, the CGN Committee approved restricted stock grants for Messrs. McGettrick, Koonce and Christian of 21,949, 23,715, and 15,505 shares (these NEOs perform services for more than one subsidiary of Dominion. These share amounts reflect only the applicable portion related to their service for Virginia Power in the year presented), respectively, to secure their services for the next three years. In making the restricted stock grants, the CGN Committee considered the increasing competitiveness of both the utility industry and general industry in retaining executive level officers, especially chief financial officers, chief operating officers and nuclear executives, and succession planning.

Each restricted stock grant is subject to three-year cliff vesting with all shares vesting on December 20, 2015 (the Vesting Date). The officer will forfeit the restricted stock grant if his employment with Dominion terminates prior to the Vesting Date for any reason other than a change in control, death or disability. In the event of a change in control, death or disability, the restricted shares are subject to vesting on a pro-rated basis. Dividends will be paid on the restricted shares, but will be retained and subject to the same vesting terms as the restricted shares. To the extent the officer remains an employee of Dominion or a Dominion Company, net shares of vested restricted stock under each agreement must be retained for two years following the Vesting Date unless the officer dies or becomes disabled.

Employee and Executive Benefits

Benefit plans and limited perquisites compose the fourth element of the compensation program. These benefits serve as a retention tool and reward long-term employment.

RETIREMENT PLANS

Dominion sponsors two types of tax-qualified retirement plans for eligible non-union employees, including the NEOs: a defined benefit pension plan (DPP) and a defined contribution 401(k)

savings plan. The NEOs, as employees hired before 2008, are eligible for a pension benefit upon attainment of retirement age based on a formula that takes into account final compensation and years of service. They also receive a cash retirement benefit under which Dominion contributes 2% of each participant’s compensation to a special retirement account, which may be paid in a lump sum or added to the annuity benefit upon retirement. Dominion began funding the special retirement account for eligible employees in January 2001. The formula for the DPP is explained in the narrative following the Pension Benefits table. The change in DPP value for 2012 for the NEOs is included in the Summary Compensation Table.

Officers whose matching contributions under the 401(k) Plan are limited by the IRC receive a cash payment to make them whole for the company match lost as a result of these limits. These cash payments are currently taxable. The company matching contributions to the 401(k) Plan and the cash payments of company matching contributions above IRC limits for the NEOs are included in the All Other Compensation column of the Summary Compensation Table and detailed in the footnote for that column.

Dominion also maintains two nonqualified retirement plans for its executives, the BRP and the ESRP. Unlike the DPP and 401(k) Plan, these plans are unfunded, unsecured obligations of Dominion. These plans keep Dominion competitive in attracting and retaining officers. Due to IRC limits on pension plan benefits and because a more substantial portion of total compensation for officers is paid as incentive compensation than for other employees, the DPP and 401(k) Plan alone will produce a lower percentage of replacement income in retirement for officers than these plans will for other employees. The BRP restores benefits that will not be paid under the DPP due to the IRC limits. The ESRP provides a benefit that covers a portion (25%) of final base salary and target annual incentive compensation to partially make up for this gap in retirement income. The BRP and ESRP do not include long-term incentive compensation in benefit calculations and, therefore, a significant portion of the potential compensation for the officers is excluded from calculation in any retirement plan benefit. As consideration for the benefits earned under the BRP and ESRP, all officers agree to comply with confidentiality and one-year non-competition requirements set forth in the plan documents following their retirement or other termination of employment. The present value of accumulated benefits under these retirement plans is disclosed in the Pension Benefits table and the terms of the plans are fully explained in the narrative following that table.

In individual situations and primarily for mid-career changes or retention purposes, the CGN Committee has granted certain officers additional years of credited age and service for purposes of calculating benefits under the BRP. Age and service credits granted to the NEOs are described in Dominion Retirement Benefit Restoration Plan under Pension Benefits. Additional age and service may also be earned under the terms of an officer’s Employee Continuity Agreement in the event of a change in control, as described in Change in Control under Potential Payments Upon Termination or Change in Control. No additional years of age or service credit were granted to the NEOs during 2012.

138

OTHER BENEFIT PROGRAMS

Dominion’s officers participate in all of the benefit programs available to other Dominion employees. The core benefit programs generally include medical, dental and vision benefit plans, a health savings account, health and dependent care flexible spending accounts, group-term life insurance, travel accident coverage, long-term disability coverage and a paid time off program.

Dominion also maintains an executive life insurance program for officers to replace a former company-wide retiree life insurance program that was discontinued in 2003. The plan is fully insured by individual policies that provide death benefits at a fixed amount depending on an officer’s salary tier. This life insurance coverage is in addition to the group-term insurance that is provided to all employees. The officer is the owner of the policy and Dominion makes premium payments until the later of 10 years from enrollment date or the date the officer attains age 64. Officers are taxed on the premiums paid by Dominion. The premiums for these policies are included in the All Other Compensation column of the Summary Compensation Table.

PERQUISITES

Dominion provides a limited number of perquisites for officers to enable them to perform their duties and responsibilities as efficiently as possible and to minimize distractions. The CGN Committee annually reviews the perquisites to ensure they are an effective and efficient use of corporate resources. Dominion believes the benefits it receives from offering these perquisites outweigh the costs of providing them. In addition to incidental perquisites associated with maintaining an office, Dominion offers the following perquisites to all officers:

Ÿ An allowance of up to $9,500 a year to be used for health club memberships and wellness programs, comprehensive executive physical exams and financial and estate planning. Dominion wants officers to be proactive with preventive healthcare and also wants executives to use professional, independent financial and estate planning consultants to ensure proper tax reporting of company-provided compensation and to help officers optimize their use of Dominion’s retirement and other employee benefit programs.

Ÿ A vehicle leased by Dominion, up to an established lease-payment limit (if the lease payment exceeds the allowance, the officer pays for the excess amount on the vehicle). The costs of insurance, fuel and maintenance for company-leased vehicles are paid by Dominion.

Ÿ In limited circumstances, use of company aircraft for personal travel by executive officers. For security and other reasons, the Board of Directors has directed Mr. Farrell to use the aircraft for all travel, including personal travel, whenever it is feasible to do so. His family and guests may accompany Mr. Farrell on any personal trips. The use of company aircraft for personal travel by other executive officers is limited and usually related to (i) travel with the CEO or (ii) personal travel to accommodate business demands on an executive’s schedule. With the exception of Mr. Farrell, personal use of aircraft is not available when there is a company need for the aircraft. Use of company aircraft saves substantial time and allows Dominion to have better access to the executives for business purposes. During 2012, 97% of the use of Dominion’s aircraft was for business purposes. Other than Mr. Farrell, none

of the NEOs or other executive officers used company aircraft for personal travel in 2012.

Other than costs associated with comprehensive executive physical exams (which are exempt from taxation under the IRC), these perquisites are fully taxable to officers. There is no tax gross-up for imputed income on any perquisites.

EMPLOYMENT CONTINUITY AGREEMENTS

Dominion has entered into Employment Continuity Agreements with all officers to ensure continuity in the event of a change in control at Dominion. While Dominion has determined these agreements are consistent with the practices of its peer companies, the most important reason for these agreements is to protect the company in the event of an anticipated or actual change in control of Dominion. In a time of transition, it is critical to protect shareholder value by retaining and continuing to motivate the company’s core management team. In a change in control situation, workloads typically increase dramatically, outside competitors are more likely to attempt to recruit top performers away from the company, and officers and other key employees may consider other opportunities when faced with uncertainties at their own company. Therefore, the Employment Continuity Agreements provide security and protection to officers in such circumstances for the long-term benefit of Dominion and its shareholders.

In determining the appropriate multiples of compensation and benefits payable upon a change in control, Dominion evaluated peer group and general practices and considered the levels of protection necessary to retain officers in such situations. The Employment Continuity Agreements are double-trigger agreements that require both a change in control and a qualifying termination of employment to trigger a benefit. The specific terms of the Employment Continuity Agreements are discussed in Potential Payments Upon Termination or Change in Control.

In January 2013, the CGN Committee approved the elimination of the excise tax gross up provision included in the Employment Continuity Agreement for any new officer elected after February 1, 2013.

OTHER AGREEMENTS

Dominion does not have comprehensive employment agreements or severance agreements for its NEOs. Although the CGN Committee believes the compensation and benefit programs described in this CD&A are appropriate, Dominion, as one of the nation’s largest producers and transporters of energy, is part of a constantly changing and increasingly competitive environment. In recognition of their valuable knowledge and experience and to secure and retain their services, Dominion has entered into letter agreements with certain of its NEOs to provide certain benefit enhancements or other protections, as described in Dominion Retirement Benefit Restoration Plan, Dominion Executive Supplemental Retirement Plan and Potential Payments Upon Termination or Change in Control. No new letter agreements were entered into in 2012.

139

OTHER RELEVANT COMPENSATION PRACTICES

Share Ownership Guidelines

Dominion requires officers to own and retain significant amounts of Dominion stock during their careers to align their interests with those of Dominion’s shareholders by promoting a long-term focus through long-term share ownership. The guidelines ensure that management maintains a personal stake in the company through significant equity investment in Dominion. Targeted ownership levels are the lesser of the following value or number of shares:

Position	Value/# of Shares
Chairman, President & Chief Executive Officer		8 x salary/145,000
Executive Vice President—Dominion		5 x salary/35,000
Senior Vice President—Dominion & Subsidiaries/President—Dominion Subsidiaries		4 x salary/20,000
Vice President—Dominion & Subsidiaries		3 x salary/10,000

The levels of ownership reflect the increasing level of responsibility for that officer’s position. Shares owned by an officer and his or her immediate family members as well as shares held under Dominion benefit plans contribute to the ownership targets. Restricted stock, goal-based stock and shares underlying stock options do not contribute to the ownership targets until the shares vest or the options are exercised. Dominion prohibits certain types of transactions related to Dominion stock, including owning derivative securities, hedging transactions, using margin accounts and pledging shares as collateral.

Until an officer meets his or her ownership target, an officer must retain net shares from stock option exercises and all after-tax shares from vesting restricted stock and goal-based stock awards. Dominion refers to shares held by an officer that are more than 15% above his or her ownership target as Qualifying Excess Shares. Officers may sell, gift or transfer Qualifying Excess Shares at any time, subject to insider trading rules and other policy provisions as long as the sale, gift or transfer does not cause an executive to fall below his or her ownership target.

At least annually, the CGN Committee reviews the share ownership guidelines and monitors compliance by executive officers, both individually and by the officer group as a whole. As of January 1, 2013, each NEO exceeded his share ownership target as shown below:

	Shares Owned and Counted Toward Target(1)		Share Ownership Target(2)
Thomas F. Farrell II		573,972		145,000
Mark F. McGettrick		160,559		35,000
David A. Christian		78,642		35,000
Paul D. Koonce		75,278		35,000
David A. Heacock		24,262		20,000

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Amounts shown are actual and not reduced by their Virginia Power allocation factor.

(1) Amounts in this column do not include shares of unvested restricted stock which are not counted toward ownership targets

(2) Share ownership target is the lesser of salary multiple or number of shares

Recovery of Incentive Compensation

Dominion’s Corporate Governance Guidelines authorize the Board to seek recovery of performance-based compensation paid to officers who are found to be personally responsible for fraud or intentional misconduct that causes a restatement of financial results filed with the SEC. Beginning in 2009, the CGN Committee approved a broader clawback provision for inclusion in Dominion’s AIP and long-term incentive performance grant documents. This clawback provision authorizes the CGN Committee, in its discretion and based on facts and circumstances, to recoup AIP and performance grant payouts from any employee whose fraudulent or intentional misconduct (i) directly causes or partially causes the need for a restatement of a financial statement or (ii) relates to or materially affects Dominion’s operations or the employee’s duties at the company. Dominion reserves the right to recover a payout by seeking repayment from the employee, by reducing the amount that would otherwise be payable to the employee under another company benefit plan or compensation program to the extent permitted by applicable law, by withholding future incentive compensation, or any combination of these actions. The clawback provision is in addition to, and not in lieu of, other actions Dominion may take to remedy or discipline misconduct, including termination of employment or a legal action for breach of fiduciary duty, and any actions imposed by law enforcement agencies.

Tax Deductibility of Compensation

IRC Section 162(m) generally disallows a deduction by publicly held corporations for compensation in excess of $1 million paid to the CEO and next three most highly compensated officers other than the CFO. If certain requirements are met, performance-based compensation qualifies for an exemption from the IRC Section 162(m) deduction limit. Dominion intends to provide competitive executive compensation while maximizing Dominion’s tax deduction. While the CGN Committee considers IRC Section 162(m) tax implications when designing annual and long-term compensation programs and approving payouts under such programs, it reserves the right to approve, and in some cases has approved, non-deductible compensation when corporate objectives justify the cost of being unable to deduct such compensation. Dominion’s tax department has advised the CGN Committee that the cost of any such lost tax deductions is not material to the company.

Accounting for Stock-Based Compensation

Dominion measures and recognizes compensation expense in accordance with the FASB guidance for share-based payments, which requires that compensation expense relating to share-based payment transactions be recognized in the financial statements based on the fair value of the equity or liability instruments issued. The CGN Committee considers the accounting treatment of equity and performance-based compensation when approving awards.

140

Executive Compensation

SUMMARY COMPENSATION TABLE – AN OVERVIEW

The Summary Compensation Table provides information in accordance with SEC requirements regarding compensation earned by the NEOs, stock awards made to the NEOs, as well as amounts accrued or accumulated during years reported with respect to retirement plans and other items. The NEOs include the CEO, the CFO, and the three most highly compensated executive officers of Virginia Power other than the CEO and CFO.

The amounts reported in the Summary Compensation Table and the other tables below represent the prorated compensation amounts attributable to each NEO’s services performed for Virginia Power. The percentage of each NEO’s overall Dominion services performed for Virginia Power during 2012 was as follows: Mr. Farrell, 29%; Mr. McGettrick, 46%; Mr. Koonce, 83%; Mr. Christian, 54%; and Mr. Heacock, 47%.

The following highlights some of the disclosures contained in this table for the NEOs. Detailed explanations regarding certain types of compensation paid to an NEO are included in the footnotes to the table.

Salary. The amounts in this column are the base salaries earned by the NEOs for the years indicated. For 2010, this amount also includes a 2% merit lump sum payment to all NEOs.

Stock Awards. The amounts in this column reflect the grant date fair value of the stock awards for accounting purposes for the respective year. Stock awards are reported in the year in which the awards are granted regardless of when or if the awards vest or are exercised.

Non-Equity Incentive Plan Compensation. This column includes amounts earned under two performance-based programs: the AIP and cash-based performance grant awards under Dominion’s LTIP. These performance programs are based on performance criteria established by the CGN Committee at the beginning of the performance period, with actual performance scored against the pre-set criteria by the CGN Committee at the end of the performance period.

Change in Pension Value and Nonqualified Deferred Compensation Earnings. This column shows any year-over-year increases in the annual accrual of pension and supplemental retirement benefits for the NEOs. These are accruals for future benefits that may be earned under the terms of the retirement plans, and are not actual payments made during the year to the NEOs. The amounts disclosed reflect the annual change in the

actuarial present value of benefits under defined benefit plans sponsored by Dominion, which include the tax-qualified DPP and the nonqualified plans described in the narrative following the Pension Benefits table. The annual change equals the difference in the accumulated amount for the current fiscal year and the accumulated amount for the prior fiscal year, generally using the same actuarial assumptions used for Dominion’s audited financial statements for the applicable fiscal year. Accrued benefit calculations are based on assumptions that the NEOs would retire at the earliest age at which they are projected to become eligible for full, unreduced pension benefits (including the effect of future service for eligibility purposes), instead of their unreduced retirement age based on current years of service. The application of these assumptions results in a greater increase in the accumulated amount of pension benefits for certain NEOs than would result without the application of these assumptions. This method of calculation does not increase actual benefits payable at retirement but only how much of that benefit is allocated to the increase during the years presented in the Summary Compensation Table. Please refer to the footnotes to the Pension Benefits table and the narrative following that table for additional information related to actuarial assumptions used to calculate pension benefits.

All Other Compensation. The amounts in this column disclose compensation that is not classified as compensation reportable in another column, including perquisites and benefits with an aggregate value of at least $10,000, the value of company-paid life insurance premiums, company matching contributions to an NEO’s 401(k) Plan account, and company matching contributions paid directly to the NEO that would be credited to the 401(k) Plan if IRC contribution limits did not apply.

Total. The number in this column provides a single figure that represents the total compensation either earned by each NEO for the years indicated or accrued benefits payable in later years and required to be disclosed by SEC rules in this table. It does not reflect actual compensation paid to the NEO during the year, but is the sum of the dollar values of each type of compensation quantified in the other columns in accordance with SEC rules.

141

SUMMARY COMPENSATION TABLE

The following table presents information concerning compensation paid or earned by the NEOs for the years ended December 31, 2012, 2011 and 2010, as well as the grant date fair value of stock awards and changes in pension value.

Name and Principal Position	Year		Salary(1)		Stock Awards(2)		Non-Equity Incentive Plan Compensation(3)		Change in Pension Value and Nonqualified Deferred Compensation Earnings(4)		All Other Compensation(5)		Total
Thomas F. Farrell II Chairman and Chief Executive Officer		2012	$	381,827	$	1,027,602	$	946,561	$	1,171,041	$	54,815	$	3,581,846
		2011		393,084		1,127,702		2,351,094		584,944		51,827		4,508,651
		2010		342,720		2,164,671		1,634,640		551,838		44,950		4,738,819
Mark F. McGettrick Executive Vice President and Chief Financial Officer		2012		311,880		1,632,701		480,389		1,169,718		31,291		3,625,979
		2011		320,948		485,013		1,008,431		802,520		33,962		2,650,874
		2010		305,402		413,970		841,435		1,590,831		33,281		3,184,919
David A. Christian President and COO—Dominion Generation		2012		323,858		1,166,905		364,726		1,188,167		51,191		3,094,847
		2011		309,329		309,058		608,095		682,795		52,785		1,962,062
		2010		299,384		225,247		554,103		661,527		49,013		1,789,274
Paul D. Koonce President and COO—DVP		2012		429,614		1,764,103		531,159		1,115,497		46,657		3,887,030
		2011		423,840		471,012		1,107,655		695,145		49,323		2,746,975
		2010		431,679		478,139		998,467		642,025		40,721		2,591,031
David A. Heacock President and CNO		2012		206,435		117,665		159,303		462,314		22,968		968,685
		2011		215,395		128,803		318,493		388,820		20,921		1,072,432
		2010		195,288		114,750		292,961		346,705		19,595		969,299

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.

⁽¹⁾ The NEOs received the following base salary increases effective March 1, 2012: Messrs. Farrell and Christian: 7.5%; Mr. Heacock: 4%; and Messrs. McGettrick and Koonce: 3%.

⁽²⁾ The amounts in this column reflect the grant date fair value of stock awards for the respective year grant in accordance with FASB guidance for share-based payments. Dominion did not grant any stock options in 2012. See also Note 19 to the Consolidated Financial Statements in the companies’ 2012 Annual Report on Form 10-K for more information on the valuation of stock-based awards, the Grants of Plan-Based Awards table for stock awards granted in 2012, and the Outstanding Equity Awards at Fiscal Year-End table for a listing of all outstanding equity awards as of December 31, 2012.

⁽³⁾ The 2012 amounts in this column include the payout under Dominion’s 2012 AIP and 2011 Performance Grant Awards. All of the NEOs received 60% funding of their 2012 AIP target awards. Messrs. Farrell and McGettrick received 99% payouts for accomplishment of their goals while Messrs. Christian and Heacock received 96% and Mr. Koonce received 100%. The 2012 AIP payout amounts were as follows: Mr. Farrell: $286,842; Mr. McGettrick: $186,161; Mr. Christian: $169,863; Mr. Koonce: $233,123; and Mr. Heacock: $83,771. See CD&A for additional information on the 2012 AIP and the Grants of Plan-Based Awards table for the range of each NEO’s potential award under the 2012 AIP. The 2011 Performance Grant Award was issued on February 1, 2011 and the payout amount was determined based on achievement of performance goals for the performance period ended December 31, 2012. Payouts can range from 0% to 200%. The actual payout was 64.2% of the target amount. The payout amounts were as follows: Mr. Farrell: $659,719; Mr. McGettrick: $294,229; Mr. Christian: $194,863; Mr. Koonce: $298,036; and Mr. Heacock: $75,531. The 2011 amounts reflect both the 2011 AIP and the 2010 Performance Grant payouts, and the 2010 amounts reflect both the 2010 AIP and 2009 Performance Grant payouts.

⁽⁴⁾ All amounts in this column are for the aggregate change in the actuarial present value of the NEO’s accumulated benefit under the DPP and nonqualified executive retirement plans. There are no above-market earnings on nonqualified deferred compensation plans. These accruals are not directly in relation to final payout potential, and can vary significantly year over year based on (i) promotions and corresponding changes in salary; (ii) other one-time adjustments to salary or incentive target for market or other reasons; (iii) actual age versus predicted age at retirement; (iv) discount rate used to determine present value of benefit; and (v) other relevant factors.

⁽⁵⁾ All Other Compensation amounts for 2012 are as follows:

Name	Executive Perquisites(a)		Life Insurance Premiums		Employee 401(k) Plan Match(b)		Company Match Above IRS Limits(c)		Total All Other Compensation
Thomas F. Farrell II	$	31,629	$	8,646	$	2,202	$	12,338	$	54,815
Mark F. McGettrick		12,145		6,670		4,583		7,893		31,291
David A. Christian		15,491		22,745		5,396		7,559		51,191
Paul D. Koonce		22,768		11,000		6,190		6,699		46,657
David A. Heacock		9,068		5,642		4,706		3,552		22,968

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the appropriate NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.

(a) Unless noted, the amounts in this column for all NEOs are comprised of the following: personal use of company vehicle and financial planning and health and wellness allowance. For Mr. Farrell, the amounts in this column also include personal use of the corporate aircraft. The value of Mr. Farrell’s personal use of the aircraft during 2012 was $23,537. For personal flights, all direct operating costs are included in calculating aggregate incremental cost. Direct operating costs include the following: fuel, airport fees, catering, ground transportation and crew expenses (any food, lodging and other costs). The fixed costs of owning the aircraft and employing the crew are not taken into consideration, as more than 97% of the use of the corporate aircraft is for business purposes. The CGN Committee has directed Mr. Farrell to use corporate aircraft for all personal travel whenever it is feasible to do so.

142

(b) Employees initially hired before 2008 who contribute to the 401(k) Plan receive a matching contribution of 50 cents for each dollar contributed up to 6% of compensation (subject to IRS limits) for employees who have less than 20 years of service, and 67 cents for each dollar contributed up to 6% of compensation (subject to IRS limits) for employees who have 20 or more years of service.

(c) Represents each payment of lost 401(k) Plan matching contribution due to IRS limits.

GRANTS OF PLAN-BASED AWARDS

The following table provides information about stock awards and non-equity incentive awards granted to the NEOs during the year ended December 31, 2012.

Name	Grant Date(1)	Grant Approval Date(1)	Estimated Future Payouts Under Non-Equity Incentive Plan Awards						All Other Stock Awards: Number of Shares of Stock or Units		Grant Date Fair Value of Stock and Options Award(1)(4)
			Threshold		Target		Maximum
Thomas F. Farrell II
2012 Annual Incentive Plan(2)			$	0	$	482,899	$	965,797
2012 Cash Performance Grant(3)				0		1,027,600		2,055,200
2012 Restricted Stock Grant(4)	2/1/2012	1/19/2012								20,380	$	1,027,602
Mark F. McGettrick
2012 Annual Incentive Plan(2)				0		313,402		626,804
2012 Cash Performance Grant(3)				0		486,944		973,888
2012 Restricted Stock Grant(4)	2/1/2012	1/19/2012								9,657		486,944
Executive Restricted Stock Grant(5)	12/20/2012	12/17/2012								21,949		1,145,757
David A. Christian
2012 Annual Incentive Plan(2)				0		294,901		589,802
2012 Cash Performance Grant(3)				0		357,485		714,970
2012 Restricted Stock Grant(4)	2/1/2012	1/19/2012								7,090		357,495
Executive Restricted Stock Grant(5)	12/20/2012	12/17/2012								15,505		809,410
Paul D. Koonce
2012 Annual Incentive Plan(2)				0		388,538		777,076
2012 Cash Performance Grant(3)				0		526,129		1,052,258
2012 Restricted Stock Grant(4)	2/1/2012	1/19/2012								10,435		526,137
Executive Restricted Stock Grant(5)	12/20/2012	12/17/2012								23,715		1,237,966
David A. Heacock
2012 Annual Incentive Plan(2)				0		145,437		290,873
2012 Cash Performance Grant(3)				0		117,650		235,300
2012 Restricted Stock Grant(4)	2/1/2012	1/19/2012								2,333		117,665

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.

⁽¹⁾ On January 19, 2012, the CGN Committee approved the 2012 long-term incentive compensation awards for Dominion officers, which consisted of a restricted stock grant and a cash performance grant. The 2012 restricted stock award was granted on February 1, 2012. Under the 2005 Incentive Compensation Plan, fair market value is defined as the closing price of Dominion common stock on the date of grant or, if that day is not a trading day, on the most recent trading day immediately preceding the date of grant. The fair market value for the February 1, 2012 restricted stock grant was $50.42 per share, which was Dominion’s closing stock price on February 1, 2012.

⁽²⁾ Amounts represent the range of potential payouts under the 2012 AIP. Actual amounts paid under the 2012 AIP are found in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. Under Dominion’s AIP, officers are eligible for an annual performance-based award. The CGN Committee establishes target awards for each NEO based on his salary level and expressed as a percentage of the individual NEO’s base salary. The target award is the amount of cash that will be paid if the plan is fully funded and payout goals are achieved. For the 2012 AIP, funding was based on the achievement of consolidated operating earnings goals with the maximum funding capped at 200%, as explained under the Annual Incentive Plan section of the CD&A.

⁽³⁾ Amounts represent the range of potential payouts under the 2012 performance grant of the LTIP. Payouts can range from 0% to 200% of the target award. Awards will be paid by March 15, 2014 depending on the achievement of performance goals for the two-year period ending December 31, 2013. The amount earned will depend on the level of achievement of two performance metrics: TSR—50% and ROIC—50%. TSR measures Dominion’s share performance for the two-year period ended December 31, 2013 relative to the TSR of the companies that are listed as members of the Philadelphia Stock Exchange Utility Index as of the end of the performance period. ROIC goal achievement will be scored against 2012 and 2013 budget goals.

The performance grant is forfeited in its entirety if an officer voluntarily terminates employment or is terminated with cause before the vesting date. The grants have pro-rated vesting for retirement, termination without cause, death or disability. In the case of retirement, pro-rated vesting will not occur if the CEO (or, for the CEO, the CGN Committee) determines the officer’s retirement is detrimental to the company. Payout for an officer who retires or whose employment is terminated without cause, is made following the end of the performance period so that the officer is rewarded only to the extent the performance goals are achieved. In the case of death or disability, payout is made as soon as possible to facilitate the administration of the officer’s estate or financial planning. The payout amount will be the greater of the officer’s target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominion’s financial statements.

In the event of a change in control, the performance grant is vested in its entirety and payout of the performance grant will occur as soon as administratively feasible following the change in control date at an amount that is the greater of an officer’s target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominion’s financial statements.

⁽⁴⁾ The 2012 restricted stock grant fully vests at the end of three years. The restricted stock grant is forfeited in its entirety if an officer voluntarily terminates employment or is terminated with cause before the vesting date. The restricted stock grant provides for pro-rated vesting if an officer retires, dies, becomes disabled, is terminated without cause, or if there is a change in control. In the case of retirement, pro-rated vesting will not occur if the CEO (or for the

143

CEO, the CGN Committee) determines the officer’s retirement is detrimental to the company. In the event of a change in control, pro-rated vesting is provided as of the change in control date, and full vesting if an officer’s employment is terminated, or constructively terminated by the successor entity following the change in control date but before the scheduled vesting date. Dividends on the restricted shares are paid during the restricted period at the same rate declared by Dominion for all shareholders.

⁽⁵⁾ On December 17, 2012, the CGN Committee awarded shares of restricted stock to Messrs. McGettrick, Christian and Koonce for retention purposes. Mr. McGettrick received 21,949 shares, Mr. Christian received 15,505 and Mr. Koonce received 23,715 shares (These NEOs perform services for more than one subsidiary of Dominion. These share amounts reflect only the applicable portion related to their service for Virginia Power in the year presented). The grant date was December 20, 2012 and the shares will fully vest on December 20, 2015 (Vesting Date), provided they each remain employed until that date. The officer will forfeit the restricted stock grant if employment with Dominion terminates prior to the Vesting Date for any reason other than a change in control, death or disability. In the event of a change in control, death or disability, the restricted shares are subject to vesting on a pro-rated basis. The fair market value for these retention grants was $52.20 per share, which was Dominion’s closing stock price on December 20, 2012. Dividends on the restricted shares are reinvested and the resulting shares will also maintain a restricted status throughout the term of the grant. To the extent the officer remains an employee of Dominion or a Dominion Company, net shares of vested restricted stock under each agreement must be retained for two years following the Vesting Date unless the officer dies or becomes disabled.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

The following table summarizes equity awards made to NEOs that were outstanding as of December 31, 2012. There were no unexercised or unexercisable option awards outstanding for any NEOs as of December 31, 2012.

	Stock Awards
Name	Number of Shares or Units of Stock that Have Not Vested (#)			Market Value of Shares or Units of Stock That Have Not Vested(1) ($)
Thomas F. Farrell II		27,431	(2)	$	1,420,926
		23,601	(3)		1,222,532
		20,380	(4)		1,055,684
		31,839	(5)		1,649,260
Mark F. McGettrick		11,011	(2)		570,370
		10,526	(3)		545,247
		9,657	(4)		500,233
		21,949	(6)		1,136,958
David A. Christian		6,122	(2)		317,120
		6,971	(3)		361,098
		7,090	(4)		367,262
		15,505	(6)		803,159
Paul D. Koonce		12,393	(2)		641,957
		10,662	(3)		552,292
		10,435	(4)		540,533
		23,715	(6)		1,228,437
David A. Heacock		2,826	(2)		146,387
		2,702	(3)		139,964
		2,333	(4)		120,849

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Amounts for the NEOs listed in the table reflect only the applicable portion related to their service for Virginia Power in the year presented.

⁽¹⁾ The market value is based on closing stock price of $51.80 on December 31, 2012.

⁽²⁾ Shares scheduled to vest on February 1, 2013.

⁽³⁾ Shares scheduled to vest on February 1, 2014.

⁽⁴⁾ Shares scheduled to vest on February 1, 2015.

⁽⁵⁾ Shares scheduled to vest on December 17, 2015. Amount includes dividends reinvested into additional shares that are restricted and subject to the same terms and conditions of the underlying restricted stock grant.

⁽⁶⁾ Shares scheduled to vest on December 20, 2015. Amount includes dividends reinvested into additional shares that are restricted and subject to the same terms and conditions of the underlying restricted stock grant.

144

OPTION EXERCISES AND STOCK VESTED

The following table provides information about the value realized by NEOs during the year ended December 31, 2012 on vested restricted stock awards. There were no option exercises by NEOs in 2012.

	Stock Awards
Name	Number of Shares Acquired on Vesting		Value Realized on Vesting
Thomas F. Farrell II		25,037	$	1,262,366
Mark F. McGettrick		9,770		492,603
David A. Christian		4,985		251,344
Paul D. Koonce		10,557		532,284
David A. Heacock		2,341		118,033

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.

PENSION BENEFITS

The following table shows the actuarial present value of accumulated benefits payable to NEOs, together with the number of years of benefit service credited to each NEO, under the plans listed in the table. Values are computed as of December 31, 2012, using the same interest rate and mortality assumptions used in determining the aggregate pension obligations disclosed in Dominion’s financial statements. The years of credited service and the present value of accumulated benefits were determined by the plan actuaries, using the appropriate accrued service, pay and other assumptions similar to those used for accounting and disclosure purposes. Please refer to Actuarial Assumptions Used to Calculate Pension Benefits for detailed information regarding these assumptions.

Name	Plan Name	Number of Years Credited Service(1)		Present Value of Accumulated Benefit(2)
Thomas F. Farrell II	Dominion Pension Plan		17.00	$	299,495
	Benefit Restoration Plan		28.00		3,079,682
	Supplemental Retirement Plan		28.00		4,027,674
Mark F. McGettrick	Dominion Pension Plan		28.50		659,443
	Benefit Restoration Plan		30.00		3,049,238
	Supplemental Retirement Plan		30.00		3,136,378
David A. Christian	Dominion Pension Plan		28.50		965,441
	Benefit Restoration Plan		28.50		1,930,290
	Supplemental Retirement Plan		28.50		2,567,957
Paul D. Koonce	Dominion Pension Plan		14.00		559,634
	Benefit Restoration Plan		14.00		753,813
	Supplemental Retirement Plan		14.00		3,295,194
David A. Heacock	Dominion Pension Plan		25.50		697,260
	Benefit Restoration Plan		25.50		487,554
	Supplemental Retirement Plan		25.50		663,178

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.

⁽¹⁾ Years of credited service shown in this column for the DPP are actual years accrued by an NEO from his date of participation to December 31, 2012. Service for the BRP and the ESRP is the NEO’s actual credited service as of December 31, 2012 plus any potential total credited service to the plan maximum, including any extra years of credited service granted to Messrs. Farrell and McGettrick by the CGN Committee for the purpose of calculating benefits under these plans. Please refer to the narrative below and under Dominion Retirement Benefit Restoration Plan, Dominion Executive Supplemental Retirement Plan and Potential Payments Upon Termination or Change In Control for information about the requirements for receiving extra years of credited service and the amount credited, if any, for each NEO.

⁽²⁾ The amounts in this column are based on actuarial assumptions that all of the NEOs would retire at the earliest age they become eligible for unreduced benefits, which is (i) age 60 for Messrs. Farrell, Koonce, Christian and Heacock, and (ii) age 55 for Mr. McGettrick (when he would be treated as age 60 based on his five additional years of credited age). In addition, for purposes of calculating the BRP benefits for Messrs. Farrell and McGettrick, the amounts reflect additional credited years of service granted to them pursuant to their agreements with the company (see Dominion Retirement Benefit Restoration Plan). If the amounts in this column did not include the additional years of credited service, the present value of the BRP benefit would be $1,440,225 lower for Mr. Farrell and $1,451,322 lower for Mr. McGettrick. DPP and ESRP benefits amounts are not augmented by the additional service credit assumptions.

145

Dominion Pension Plan

The DPP is a tax-qualified defined benefit pension plan. All of the NEOs participate in the DPP. The DPP provides unreduced retirement benefits at termination of employment at or after age 65 or, with three years of service, at age 60. A participant who has attained age 55 with three years of service may elect early retirement benefits at a reduced amount. If a participant retires between ages 55 and 60, the benefit is reduced 0.25% per month for each month after age 58 and before age 60, and reduced 0.50% per month for each month between ages 55 and 58. All of the NEOs have more than three years of service.

The DPP basic benefit is calculated using a formula based on (1) age at retirement; (2) final average earnings; (3) estimated Social Security benefits; and (4) credited service. Final average earnings are the average of the participant’s 60 highest consecutive months of base pay during the last 120 months worked. Final average earnings do not include compensation payable under the AIP, the value of equity awards, gains from the exercise of stock options, long-term cash incentive awards, perquisites or any other form of compensation other than base pay.

Credited service is measured in months, up to a maximum of 30 years of credited service. The estimated Social Security benefit taken into account is the assumed Social Security benefit payable starting at age 65 or actual retirement date, if later, assuming that the participant has no further employment after leaving Dominion. These factors are then applied in a formula.

The formula has different percentages for credited service through December 31, 2000 and on and after January 1, 2001. The benefit is the sum of the amounts from the following two formulas.

For credited service through December 31, 2000:
2.03% times Final Average Earnings times Credited Service before 2001	Minus	2.00% times estimated Social Security benefit times Credited Service before 2001
For credited service on or after January 1, 2001:
1.80% times Final Average Earnings times Credited Service after 2000	Minus	1.50% times estimated Social Security benefit times Credited Service after 2000

Credited service is limited to a total of 30 years for all parts of the formula and credited service after 2000 is limited to 30 years minus credited service before 2001.

Benefit payment options are (1) a single life annuity or (2) a choice of a 50%, 75% or 100% joint and survivor annuity. A Social Security leveling option is available with any of the benefit forms. The normal form of benefit is a single life annuity for unmarried participants and a 50% joint and survivor annuity for married participants. All of the payment options are actuarially equivalent in value to the single life annuity. The Social Security leveling option pays a larger benefit equal to the estimated Social Security benefit until the participant is age 62 and then reduced payments after age 62.

The DPP also includes a special retirement account, which is in addition to the pension benefit. The special retirement account is credited with 2% of base pay each month as well as interest based on the 30-year Treasury bond rate set annually (3.18% in 2012). The special retirement account can be paid in a lump sum or paid in the form of an annuity benefit.

A participant becomes vested in his or her benefit after completing three years of service. A vested participant who terminates employment before age 55 can start receiving benefit payments calculated using terminated vested reduction factors at any time after attaining age 55. If payments begin before age 65, then the following reduction factors for the portion of the benefits earned after 2000 apply: age 64 – 9%; age 63 – 16%; age 62 – 23%; age 61 – 30%; age 60 – 35%; age 59 – 40%; age 58 – 44%; age 57 – 48%; age 56 – 52%; and age 55 – 55%.

The IRC limits the amount of compensation that may be included in determining pension benefits under qualified pension plans. For 2012, the compensation limit was $250,000. The IRC also limits the total annual benefit that may be provided to a participant under a qualified defined benefit plan. For 2012, this limitation was the lesser of (i) $200,000 or (ii) the average of the participant’s compensation during the three consecutive years in which the participant had the highest aggregate compensation.

Dominion Retirement Benefit Restoration Plan

The BRP is a nonqualified defined benefit pension plan designed to make up for benefit reductions under the DPP due to the limits imposed by the IRC.

A Dominion employee is eligible to participate in the BRP if (1) he or she is a member of management or a highly compensated employee, (2) his or her DPP benefit is or has been limited by the IRC compensation or benefit limits, and (3) he or she has been designated as a participant by the CGN Committee. A participant remains a participant until he or she ceases to be eligible for any reason other than retirement or until his or her status as a participant is revoked by the CGN Committee.

Upon retirement, a participant’s BRP benefit is calculated using the same formula (except that the IRC salary limit is not applied) used to determine the participant’s default annuity form of benefit under the DPP (single life annuity for unmarried participants and 50% joint and survivor annuity for married participants), and then subtracting the benefit the participant is entitled to receive under the DPP. To accommodate the enactment of IRC Section 409A, the portion of a participant’s BRP benefit that had accrued as of December 31, 2004 is frozen, but the calculation of the overall restoration benefit is not changed.

The restoration benefit is generally paid in the form of a single lump sum cash payment. However, a participant may elect to receive a single life or 50% or 100% joint and survivor annuity for the portion of his or her benefit that accrued prior to 2005. For the portion of his or her benefit that accrued in 2005 or later, a participant may also elect to receive a 75% joint and survivor annuity. The lump sum calculation includes an amount approximately equivalent to the amount of taxes the participant will owe on the lump sum payment so that the participant will have sufficient funds, on an after-tax basis, to purchase an annuity contract.

A participant who terminates employment before he or she is eligible for benefits under the DPP generally is not entitled to a restoration benefit. Messrs. Farrell and McGettrick have been granted age and service credits for purposes of calculating their DPP and BRP benefits. Per Mr. Farrell’s letter agreement, he was granted 25 years of service when he reached age 55 and will continue to accrue service as long as he remains employed. At age 60, benefits will be calculated based on 30 years of service, if he remains employed. Mr. McGettrick, having attained age 50, has

146

earned benefits calculated based on five additional years of age and service. For each of these NEOs, the additional years of service count for determining both the amount of benefits and the eligibility to receive them. For additional information regarding service credits, see Dominion Executive Supplemental Retirement Plan.

If a vested participant dies when he or she is retirement eligible (on or after age 55), the participant’s beneficiary will receive the restoration benefit in a single lump sum payment. If a participant dies while employed but before he or she has attained age 55 and the participant is married at the time of death, the participant’s spouse will receive a restoration benefit calculated in the same way as the 50% qualified pre-retirement survivor annuity payable under the DPP and paid in a lump sum payment.

Dominion Executive Supplemental Retirement Plan

The ESRP is a nonqualified defined benefit plan that provides for an annual retirement benefit equal to 25% of a participant’s final cash compensation (base salary plus target annual incentive award) payable for a period of 10 years or, for certain participants designated by the CGN Committee, for the participant’s lifetime. To accommodate the enactment of IRC Section 409A, the portion of a participant’s ESRP benefit that had accrued as of December 31, 2004 is frozen, but the calculation of the overall benefit is not changed.

A Dominion employee is eligible to participate in the ESRP if (1) he or she is a member of management or a highly compensated employee, and (2) he or she has been designated as a participant by the CGN Committee. A participant remains a participant until he or she ceases to be eligible for any reason other than retirement or until his or her status as a participant is revoked by the CGN Committee.

A participant is entitled to the full ESRP benefit if he or she separates from service with Dominion after reaching age 55 and achieving 60 months of service. A participant who separates from service with Dominion with at least 60 months of service but who has not yet reached age 55 is entitled to a reduced, pro-rated retirement benefit. A participant who separates from service with Dominion with fewer than 60 months of service is generally not entitled to an ESRP benefit unless the participant separated from service on account of disability or death.

The ESRP benefit is generally paid in the form of a single lump sum cash payment. However, a participant may elect to receive the portion of his or her benefit that had accrued as of December 31, 2004 in monthly installments. For any new participants, the ESRP benefit must be paid in the form of a single lump sum cash payment. The lump sum calculation includes an amount approximately equivalent to the amount of taxes the participant will owe on the lump sum payment so that the participant will have sufficient funds, on an after-tax basis, to purchase a 10-year or lifetime annuity contract.

All of the NEOs except Mr. Koonce are currently entitled to a full ESRP retirement benefit. If Mr. Koonce terminates employment before attaining age 55, he will receive a pro-rated ESRP benefit. Based on the terms of their individual letter agreements, Messrs. Farrell, McGettrick and Koonce will receive an ESRP benefit calculated as a lifetime benefit. Mr. McGettrick has earned five years of additional age and service credit for purposes of computing his retirement benefits and eligibility for benefits under the ESRP, long-term incentive grants, and retiree medical and life insurance plans as he has met the requirement of remaining employed until he attained age 50. Under his letter agreement, Mr. Christian will receive ESRP benefits calculated as a lifetime benefit provided he remains employed with Dominion until attainment of age 60. As consideration for this benefit, Mr. Christian has agreed not to compete with Dominion for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.

Actuarial Assumptions Used to Calculate Pension Benefits

Actuarial assumptions used to calculate DPP benefits are prescribed by the terms of the DPP based on IRC and PBGC requirements. The present value of the accumulated benefit is calculated using actuarial and other factors as determined by the plan actuaries and approved by Dominion. Actuarial assumptions used for the December 31, 2012 benefit calculations shown in the Pension Benefits table include a discount rate of 4.40% to determine the present value of the future benefit obligations for the DPP, BRP and ESRP and a lump sum interest rate of 3.65% to estimate the lump sum values of BRP and ESRP benefits. Each NEO is assumed to retire at the earliest age at which he is projected to become eligible for full, unreduced pension benefits. Beginning with the 2009 calculations, for purposes of estimating future eligibility for unreduced DPP and ESRP benefits, the effect of future service is considered. Each NEO is assumed to commence DPP payments at the same age as BRP payments. The longevity assumption used to determine the present value of benefits is the same assumption used for financial reporting of the DPP liabilities, with no assumed mortality before retirement age. Assumed mortality after retirement is based on tables from the Society of Actuaries’ RP-2000 study, projected from 2000 to a point five years beyond the calculation date (this year, to 2017) with 100% of the Scale AA factors, and further adjusted for Dominion experience by using an age set-forward factor. For BRP and ESRP benefits, other actuarial assumptions include an assumed tax rate of 42%. BRP and ESRP benefits are assumed to be paid as lump sums; pension plan benefits are assumed to be paid as annuities.

The discount rate for calculating lump sum BRP and ESRP payments at the time an officer terminates employment is selected by Dominion’s Administrative Benefits Committee and adjusted periodically. For year 2012, a 5.09% discount rate was used to determine the lump sum payout amounts. The discount rate for each year will be based on a rolling average of the blended rate published by the PBGC in October of the previous five years.

147

NONQUALIFIED DEFERRED COMPENSATION

Name	Aggregate Earnings in Last FY (as of 12/31/2012)*		Aggregate Withdrawals/ Distributions (as of 12/31/2012)		Aggregate Balance at Last FYE (as of 12/31/2012)
Thomas F. Farrell II	$	—	$	—	$	—
Mark F. McGettrick		—		—		—
David A. Christian		256		—		15,891
Paul D. Koonce		22,404		—		1,146,855
David A. Heacock		—		—		—

*No preferential earnings are paid and therefore no earnings from these plans are included in the Summary Compensation Table. Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.

At this time, Dominion does not offer any nonqualified elective deferred compensation plans to its officers or other employees. The Nonqualified Deferred Compensation table reflects, in aggregate, the plan balances for two former plans offered to Dominion officers and other highly compensated employees: the Frozen Deferred Compensation Plan and the Frozen DSOP, which were frozen as of December 31, 2004. Although the Frozen DSOP was an option plan rather than a deferred compensation plan, Dominion is including information regarding the plan and any balances in this table to make full disclosure about possible future payments to officers under Dominion’s employee benefit plans.

Frozen Deferred Compensation Plan

The Frozen Deferred Compensation Plan includes amounts previously deferred from one of the following categories of compensation: (i) salary; (ii) bonus; (iii) vesting restricted stock; and (iv) gains from stock option exercises. The plan also provided for company contributions of lost company 401(k) Plan match contributions and transfers from several CNG deferred compensation plans. The Frozen Deferred Compensation Plan offers 27 investment funds for the plan balances, including a Dominion Resources Stock Fund. Participants may change investment elections on any business day. Any vested restricted stock and gains from stock option exercises that were deferred were automatically allocated to the Dominion Resources Stock Fund and this allocation cannot be changed. Earnings are calculated based on the performance of the underlying investment fund.

The following funds had rates of returns for 2012 as follows: Dominion Resources Stock Fund, 1.66%; and Dominion Fixed Income Fund, 3.31%.

The Dominion Fixed Income Fund is an investment option that provides a fixed rate of return each year based on a formula that is tied to the adjusted federal long-term rate published by the IRS in November prior to the beginning of the year. Dominion’s Asset Management Committee determines the rate based on its estimate of the rate of return on Dominion assets in the trust for the Frozen Deferred Compensation Plan.

The default Benefit Commencement Date is February 28 after the year in which the participant retires, but the participant may select a different Benefit Commencement Date in accordance with the plan. Participants may change their Benefit Commencement Date election; however, a new election must be made

at least six months before an existing Benefit Commencement Date. Withdrawals less than six months prior to an existing Benefit Commencement Date are subject to a 10% early withdrawal penalty. Account balances must be fully paid out no later than the February 28 that is 10 calendar years after a participant retires or becomes disabled. If a participant retires from Dominion, he or she may continue to defer an account balance provided that the total balance is distributed by this deadline. In the event of termination of employment for reasons other than death, disability or retirement before an elected Benefit Commencement Date, benefit payments will be distributed in a lump sum as soon as administratively practicable. Hardship distributions, prior to an elected Benefit Commencement Date, are available under certain limited circumstances.

Participants may elect to have their benefit paid in a lump sum payment or equal annual installments over a period of whole years from one to 10 years. Participants have the ability to change their distribution schedule for benefits under the plan by giving six months notice to the plan administrator. Once a participant begins receiving annual installment payments, the participant can make a one-time election to either (1) receive the remaining account balance in the form of a lump sum distribution or (2) change the remaining installment payment period. Any election must be approved by the company before it is effective. All distributions are made in cash with the exception of the Deferred Restricted Stock Account and the Deferred Stock Option Account, which are distributed in the form of Dominion common stock.

Frozen DSOP

The Frozen DSOP enabled employees to defer all or a portion of their salary and bonus and receive options on various mutual funds. Participants also received lost company matching contributions to the 401(k) Plan in the form of options under this plan. DSOP options can be exercised at any time before their expiration date. On exercise, the participant receives the excess of the value, if any, of the underlying mutual funds over the strike price. The participant can currently choose among options on 27 mutual funds, and there is not a Dominion stock alternative or a fixed income fund. Participants may change options among the mutual funds on any business day. Benefits grow/decline based on the total return of the mutual funds selected. Any options that expire do not have any value. Options expire under the following terms:

Ÿ Options expire on the last day of the 120th month after retirement or disability;

Ÿ Options expire on the last day of the 24th month after the participant’s death (while employed);

Ÿ Options expire on the last day of the 12th month after the participant’s severance;

Ÿ Options expire on the 90th day after termination with cause; and

Ÿ Options expire on the last day of the 120th month after severance following a change in control.

The NEO participating in the Frozen DSOP held options on the publicly available mutual fund, Vanguard Short-Term Bond Index, which had a rate of return for 2012 of 1.95%.

148

POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL

Under certain circumstances, Dominion provides benefits to eligible employees upon termination of employment, including a termination of employment involving a change in control of Dominion, that are in addition to termination benefits for other employees in the same situation.

Change in Control

As discussed in the Employee and Executive Benefits section of the CD&A, Dominion has entered into an Employment Continuity Agreement with each of its officers, including the NEOs. Each agreement has a three-year term and is automatically extended annually for an additional year, unless cancelled by Dominion.

The Employment Continuity Agreements require two triggers for the payment of most benefits:

Ÿ There must be a change in control; and

Ÿ The executive must either be terminated without cause, or terminate his or her employment with the surviving company after a constructive termination. Constructive termination means the executive’s salary, incentive compensation or job responsibility is reduced after a change in control or the executive’s work location is relocated more than 50 miles without his or her consent.

For purposes of the Employment Continuity Agreements, a change in control will occur if (i) any person or group becomes a beneficial owner of 20% or more of the combined voting power of Dominion voting stock or (ii) as a direct or indirect result of, or in connection with, a cash tender or exchange offer, merger or other business combination, sale of assets, or contested election, the directors constituting the Dominion Board before any such transaction cease to represent a majority of Dominion’s or its successor’s Board within two years after the last of such transactions.

If an executive’s employment following a change in control is terminated without cause or due to a constructive termination, the executive will become entitled to the following termination benefits:

Ÿ Lump sum severance payment equal to three times base salary plus AIP award (determined as the greater of (i) the target annual award for the current year or (ii) the highest actual AIP payout for any one of the three years preceding the year in which the change in control occurs).

Ÿ Full vesting of benefits under ESRP and BRP with five years of additional credited age and five years of additional credited service from the change in control date.

Ÿ Group-term life insurance. If the officer elects to convert group-term insurance to an individual policy, the company pays the premiums for 12 months.

Ÿ Executive life insurance. Premium payments will continue to be paid by Dominion until the earlier of: (1) the fifth anniversary of the termination date, or (2) the later of the 10th anniversary of the policy or the date the officer attains age 64.

Ÿ Retiree medical coverage will be determined under the relevant plan with additional age and service credited as provided under an officer’s letter of agreement (if any) and including five additional years credited to age and five additional years credited to service.

Ÿ Outplacement services for one year (up to $25,000).

Ÿ If any payments are classified as excess parachute payments for purposes of IRC Section 280G and the executive incurs the excise tax, Dominion will pay the executive an amount equal to the 280G excise tax plus a gross-up multiple.

In January 2013, the CGN Committee approved the elimination of the excise tax gross up provision included in the Employment Continuity Agreement for any new officer elected after February 1, 2013.

The terms of awards made under the LTIP, rather than the terms of Employment Continuity Agreements, will determine the vesting of each award in the event of a change in control. These provisions are described in the Long-Term Incentive Program section of the CD&A and footnotes to the Grants of Plan-Based Awards table.

Other Post Employment Benefit for Mr. Farrell

Mr. Farrell will become entitled to a payment of one times salary upon his retirement as consideration for his agreement not to compete with Dominion for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.

149

The following table provides the incremental payments that would be earned by each NEO if his employment had been terminated, or constructively terminated, as of December 31, 2012. These benefits are in addition to retirement benefits that would be payable on any termination of employment. Please refer to the Pension Benefits table for information related to the present value of accumulated retirement benefits payable to the NEOs.

Incremental Payments Upon Termination or Change in Control

Name	Non-Qualified Plan Payment		Restricted Stock(1)		Performance Grant(1)		Non-Compete Payments(2)		Severance Payments		Retiree Medical and Executive Life Insurance(3)	Outplacement Services		Excise Tax & Tax Gross-Up		Total
Thomas F. Farrell II(4)
Retirement		$—	$	2,485,126	$	491,461	$	386,319		$—	$—		$—		$—	$	3,362,906
Death / Disability		—		3,144,840		491,461		—		—	—		—		—		3,636,301
Change in Control(5)		588,482		1,873,837		536,139		—		2,929,365	—		7,340		—		5,935,163
Mark F. McGettrick(4)
Retirement		—		1,055,715		232,886		—		—	—		—		—		1,288,601
Death / Disability		—		1,087,289		232,886		—		—	—		—		—		1,320,175
Change in Control(5)		—		1,697,168		254,058		—		2,139,402	—		11,458		—		4,102,086
David A. Christian(4)
Retirement		—		651,237		170,971		—		—	—		—		—		822,208
Death / Disability		—		673,542		170,971		—		—	—		—		—		844,513
Change in Control(5)		375,375		1,197,516		186,514		—		2,004,106	—		13,490		1,329,761		5,106,762
Paul D. Koonce
Termination Without Cause		—		1,142,123		251,627		—		—	—		—		—		1,393,750
Voluntary Termination		—		—		—		—		—	—		—		—		—
Termination With Cause		—		—		—		—		—	—		—		—		—
Death / Disability		—		1,176,238		251,627		—		—	—		—		—		1,427,865
Change in Control(5)		2,120,693		1,821,216		274,502		—		2,781,824	11,102		20,633		—		7,029,970
David A. Heacock(4)
Retirement		—		268,709		56,267		—		—	—		—		—		324,976
Change in Control(5)		756,132		138,584		61,383		—		1,119,029	75,093		11,765		783,353		2,945,339

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the applicable portion related to their service for Virginia Power in the year presented.

⁽¹⁾ Grants made in 2010, 2011 and 2012 under the LTIP vest prorated upon termination without cause, death or disability. These grants vest prorated upon retirement provided the CEO of Dominion (or in the case of the CEO, the CGN Committee) determines the NEO’s retirement is not detrimental to the company; amounts shown assume this determination was made. However, the December 2010 restricted stock award issued to Mr. Farrell and the December 2012 restricted stock awards issued to Messrs. McGettrick, Christian and Koonce do not vest prorated if the executive is terminated or leaves for any reason other than following change of control, death or disability. The amounts shown in the restricted stock column are based on the closing stock price of $51.80 on December 31, 2012.

⁽²⁾ Pursuant to a letter agreement dated February 28, 2003, Mr. Farrell will be entitled to a special payment of one times salary upon retirement in exchange for a two-year non-compete agreement. Mr. Farrell would not be entitled to this non-compete payment in the event of his death.

⁽³⁾ Amounts in this column represent the value of the annual incremental benefit the NEOs would receive for executive life insurance and retiree medical coverage. Mr. McGettrick is eligible for retiree medical and executive life insurance upon any termination due to his letter agreement. Messrs. Farrell and Christian are entitled to executive life insurance coverage and retiree medical benefit upon any termination since they are retirement eligible and have completed 10 years of service. Mr. Heacock is entitled to executive life insurance coverage since he has reached the age of 55 and has 10 years of service. Mr. Koonce is eligible for executive life insurance upon a change in control. Mr. Heacock is eligible for retiree medical coverage upon a change in control. Mr. Koonce would not be eligible for retiree medical coverage upon a change in control because with an additional 5 years of age credit he would not reach the required retiree medical age of 58. Retiree health benefits have been quantified using assumptions used for financial accounting purposes.

⁽⁴⁾ For the NEOs who are eligible for retirement (Messrs. Farrell, McGettrick, Christian and Heacock), this table above assumes they would retire in connection with any termination event.

⁽⁵⁾ Change in control amounts assume that a change in control and a termination or constructive termination takes place on December 31, 2012. The amounts indicated upon a change in control are the incremental amounts attributable to five years of additional age and service credited pursuant to the Employment Continuity Agreements that each NEO would receive over the amounts payable upon a retirement (Messrs. Farrell, McGettrick, Christian, and Heacock) or termination without cause (Mr. Koonce). The restricted stock and performance grant amounts represent the value of the awards upon a change in control that is above what would be received upon a retirement or termination.

150

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

DOMINION

The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the headings Share Ownership-Director and Officer Share Ownership and Significant Shareholders in the 2013 Proxy Statement is incorporated by reference.

The information regarding equity securities of Dominion that are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation-Equity Compensation Plans in the 2013 Proxy Statement is incorporated by reference.

VIRGINIA POWER

The table below sets forth as of February 15, 2013, the number of shares of Dominion common stock owned by directors and executive officers of Virginia Power named on the Summary Compensation Table. Dominion owns all of the outstanding common stock of Virginia Power. None of the executive officers or directors own any of the outstanding preferred stock of Virginia Power.

Name of Beneficial Owner	Shares		Restricted Shares		Total(1)
Thomas F. Farrell II		624,714		335,782		960,496
Mark F. McGettrick		175,794		113,510		289,304
Steven A. Rogers		53,431		11,368		64,799
David A. Christian		86,198		68,250		154,448
David A. Heacock		28,315		16,240		44,555
Paul D. Koonce		69,099		67,754		136,853
All directors and executive officers as a group (8 persons)(2)		1,082,890		637,935		1,720,825

⁽¹⁾  Includes shares as to which voting and/or investment power is shared with or controlled by another person as follows: Mr. Farrell, 20,000 (shares held jointly); Mr. Rogers, 669 (shares held in joint tenancy); all directors and executive officers as a group, 36,138.

⁽²⁾  Neither any individual director or executive officer, nor all of the directors and executive officers as a group, own more than one percent of Dominion common shares outstanding as of February 15, 2013.

Item 13. Certain Relationships and Related Transactions, and Director Independence

DOMINION

The information regarding related party transactions required by this item found under the heading Related Party Transactions, and information regarding director independence found under the heading Director Independence, in the 2013 Proxy Statement is incorporated by reference.

VIRGINIA POWER

Related Party Transactions

Virginia Power’s Board of Directors has adopted the Related Party Guidelines also approved by Dominion’s Board of Direc-

tors. These guidelines were adopted for the purpose of identifying potential conflicts of interest arising out of financial transactions, arrangements and relations between Virginia Power and any related persons. Under the guidelines, a related person is a director, executive officer, director nominee, a beneficial owner of more than 5% of Dominion’s common stock, or any immediate family member of one of the foregoing persons. A related party transaction is any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships in excess of $120,000 in which Virginia Power (and/or any of its consolidated subsidiaries) is a party and in which the related person has or will have a direct or indirect material interest.

In determining whether a direct or indirect interest is material, the significance of the information to investors in light of all circumstances is considered. The importance of the interest to the person having the interest, the relationship of the parties to the transaction with each other and the amount involved are also among the factors considered in determining the significance of the information to the investors.

Dominion’s CGN Committee has reviewed certain categories of transactions and determined that transactions between Dominion and a related person that fall within such categories will not result in the related person receiving a direct or indirect material interest. Under the guidelines, such transactions are not deemed related party transactions and therefore not subject to review by the CGN Committee. The categories of excluded transactions include, among other items, compensation and expense reimbursement paid to directors and executive officers in the ordinary course of performing their duties; transactions with other companies where the related party’s only relationship is as an employee, if the aggregate amount involved does not exceed the greater of $1 million or 2% of that company’s gross revenues; and charitable contributions which are less than the greater of $1 million or 2% of the charity’s annual receipts. The full text of the guidelines can be found on Dominion’s website at www.dom.com/investors/corporate-governance/pdf/related_party_guidelines.pdf.

Virginia Power collects information about potential related party transactions in its annual questionnaires completed by directors and executive officers. Management reviews the potential related party transactions and assesses whether any of the identified transactions constitute a related party transaction. Any identified related party transactions are then reported to Dominion’s CGN Committee. Dominion’s CGN Committee reviews and considers relevant facts and circumstances and determines whether to ratify or approve the related party transactions identified. Dominion’s CGN Committee may only approve or ratify related party transactions that are in, or are not inconsistent with, the best interests of Dominion and its shareholders and are in compliance with Virginia Power’s Code of Ethics.

Since January 1, 2012, there have been no related party transactions involving Virginia Power that were required either to be approved under Virginia Power’s policies or reported under the SEC related party transactions rules.

151

Director Independence

Under NYSE listing standards, Messrs. Farrell, McGettrick and Rogers are not independent as they were executive officers of Virginia Power or of its parent company, Dominion. All of Virginia Power’s outstanding common stock is owned by Dominion and therefore, Virginia Power is a “controlled” company under the rules of the NYSE. Because Virginia Power meets the definition of a “controlled company” and has only preferred stock listed on the NYSE, it is exempt under Section 303A of the NYSE Rules from the provisions relating to board committees and the requirement to have a majority of its board be independent.

Item 14. Principal Accountant Fees and Services

DOMINION

The information concerning principal accountant fees and services contained under the heading Auditors-Fees and Pre-Approval Policy in the 2013 Proxy Statement is incorporated by reference.

VIRGINIA POWER

The following table presents fees paid to Deloitte & Touche LLP for the fiscal years ended December 31, 2012 and 2011.

Type of Fees	2012		2011
(millions)
Audit fees	$	1.79	$	1.32
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
	$	1.79	$	1.32

Audit Fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power’s annual consolidated financial statements, the review of financial statements included in Virginia Power’s quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC.

Virginia Power’s Board of Directors has adopted the Dominion Audit Committee pre-approval policy for its independent auditor’s services and fees and has delegated the execution of this policy to the Dominion Audit Committee. In accordance with this delegation, each year the Dominion Audit Committee pre-approves a schedule that details the services to be provided for the following year and an estimated charge for such services. At its December 2012 meeting, the Dominion Audit Committee approved Virginia Power’s schedule of services and fees for 2013. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Audit Committee or a member of the Dominion Audit Committee.

152

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.

1. Financial Statements

See Index on page 53.

2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.

3. Exhibits (incorporated by reference unless otherwise note

Exhibit Number	Description	Dominion		Virginia Power
2	Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1, Form 8-K filed March 15, 2010, File No. 1-8489).		X
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 December 13, 2011 (Exhibit 3.1, Form 8-K filed December 14, 2011, File No. 1-8489).		X
3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).				X
4	Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.		X		X
4.1.a	See Exhibit 3.1.a above.		X
4.1.b	See Exhibit 3.1.b above.				X
4.2	Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); Ninety-Second Supplemental Indenture, dated as of July 1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255).		X		X
4.3	Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of First Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Eleventh Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255); Forms of Twelfth and Thirteenth Supplemental Indentures, dated January 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Forms of Sixteenth and Seventeenth Supplemental Indentures, dated November 1, 2007 (Exhibits 4.2 and 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008		X		X

153

Exhibit Number	Description	Dominion		Virginia Power
	(Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255).
4.4	Indenture, Junior Subordinated Debentures, dated December 1, 1997, 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 supplemented by a First Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement filed April 22, 1998, File No. 333-50653); Forms of Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits 4.6 and 4.13, Form 8-K filed January 12, 2001, File No. 1-8489).		X
4.5	Indenture, dated May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012); Fifteenth Supplemental Indenture, dated October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651); Seventeenth Supplemental Indenture, dated August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Eighteenth Supplemental Indenture, dated December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Nineteenth Supplemental Indenture, dated January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Twentieth Supplemental Indenture, dated March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-3196); Twenty-First Supplemental Indenture, dated June 27, 2007 (Exhibit 4.2, Form 8-K filed July 3, 2007, File No. 1-8489).		X
4.6	Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2, Form 8-A filed April 21, 1995, File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2, Form 8-A filed December 12, 1996, File No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2, Form 8-A filed October 22, 1998, File No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004); Second Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.4, Form 8-K filed July 3, 2007, File No. 1-8489).		X
4.7	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		X

154

Exhibit Number	Description	Dominion		Virginia Power
	Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Forms of Seventeenth and Eighteenth Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489; Forms of Twentieth and Twenty-First Supplemental Indentures, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Third Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011(Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K, filed March 7, 2011, File No. 1-8489);Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 15, 2011, File No. 1-8489); Forty-Fifth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489).
4.8	Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K filed April 12, 2001, File No. 1-3196); Forms of Second and Third Supplemental Indentures, dated October 25, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed October 23, 2001, File No. 1-3196); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K filed May 22, 2002, File No. 1-3196); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196); Seventh Supplemental Indenture, dated June 27, 2007 (Exhibit 4.6, Form 8-K filed July 3, 2007, File No. 1-8489).		X
4.9	Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489).		X
4.10	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 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).		X

155

Exhibit Number	Description	Dominion		Virginia Power
4.11	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 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).		X
4.12	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489).		X
10.1	DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489).		X
10.2	DRS Services Agreement, dated as of January 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255).				X
10.3	Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489).		X		X
10.4	$3.0 billion Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, JP Morgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., Barclays Capital, The Royal Bank of Scotland plc, and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein. (Exhibit 10.1, Form 8-K filed September 28, 2010, File No. 1-8489 and File No. 1-2255), as amended October 1, 2011 (Exhibit 10.1, Form 8-K filed October 3, 2011, File No. 1-8489 and File No. 1-2255).		X		X
10.5	$500 million Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, Keybank National Association, as Administrative Agent, Bayerische Landesbank, New York Branch, and U.S. Bank National Association, as Syndication Agents, and other lenders named therein. (Exhibit 10.2, Form 8-K filed September 28, 2010, File No. 1-8489 and File No. 1-2255), as amended October 1, 2011 (Exhibit 10.2, Form 8-K filed October 3, 2011, File No. 1-8489 and File No. 1-2255).		X		X
10.6	Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003, File No. 1-8489 and File No. 1-2255).		X		X
10.7*	Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X
10.8*	Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489), as amended June 20, 2007 (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489 and Exhibit 10.5, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-2255).		X		X
10.9*	Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489).		X		X
10.10*	Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X
10.11*	Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X
10.12*	Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489), amended January 19, 2006 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2005 filed March 2, 2006, File No. 1-8489), as amended December 1, 2006 and further amended January 1, 2007 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2006, filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489).		X		X

156

Exhibit Number	Description	Dominion		Virginia Power
10.13*	Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489), as amended January 1, 2007 (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255), as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255).		X		X
10.14*	Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489).		X
10.15*	Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).		X
10.16*	Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489).		X
10.17*	Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489).		X
10.18*	Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489 and File No. 1-2255).		X		X
10.19*	Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011 (Exhibit 10.22, Form 10-K filed February 28, 2011, File No. 1-8489).		X
10.20*	Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X
10.21*	Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).		X
10.22*	Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489).		X
10.23*	Supplemental retirement agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255).		X
10.24*	Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255).		X
10.25*	Form of Restricted Stock Grant under 2007 Long-Term Compensation Program approved March 30, 2007 (Exhibit 10.1, Form 8-K filed April 5, 2007, File No. 1-8489).		X		X
10.26*	Form of Restricted Stock Award Agreement under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.1, Form 8-K filed April 2, 2008, File No. 1-8489).		X		X
10.27*	Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255).		X		X

157

Exhibit Number	Description	Dominion		Virginia Power
10.28*	2009 Performance Grant Plan under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.1, Form 8-K filed January 29, 2009, File No. 1-8489).		X		X
10.29*	Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489).		X		X
10.30*	Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective December 20, 2011 (Exhibit 10.32, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255).		X		X
10.31*	2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489).		X		X
10.32*	Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489).		X		X
10.33*	Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489).		X		X
10.34*	2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489).		X		X
10.35*	Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489).		X		X
10.36*	Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian under the 2005 Incentive Compensation Plan approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012, File No. 1-8489).		X		X
10.37*	2012 Performance Grant Plan under the 2012 Long-Term Incentive Program approved January 19, 2012 (Exhibit 10.1, Form 8-K filed January 20, 2012, File No. 1-8489).		X		X
10.38*	Form of Restricted Stock Award Agreement under the 2012 Long-term incentive Program approved January 19, 2012 (Exhibit 10.2, Form 8-K filed January 20, 2012, File No. 1-8489).		X		X
10.39*	2013 Performance Grant Plan under 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.1, Form 8-K filed January 25, 2013, File No. 1-8489).		X		X
10.40*	Form of Restricted Stock Award Agreement under the 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.2, Form 8-K filed January 25, 2013, File No. 1-8489).		X		X
10.41*	Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010 (Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489).		X		X
10.42*	Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).		X
10.43*	Non-employee directors’ annual compensation for Dominion Resources, Inc. (filed herewith).		X
12.a	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).		X
12.b	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).				X
12.c	Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).				X
21	Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith).		X		X
23	Consent of Deloitte & Touche LLP (filed herewith).		X		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

158

Exhibit Number	Description	Dominion		Virginia Power
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
99.1	Dominion Resources, Inc. Earnings Release Kit (furnished herewith).		X
99.2	Supplemental Summary of 2012 Operating Earnings (furnished herewith).		X
99.3	Towers Watson Energy Services Survey participants (filed herewith).				X
101^	The following financial statements from Dominion Resources, Inc. and Virginia Electric and Power Company Annual Report on Form 10-K for the year ended December 31, 2012, filed on February 28, 2013, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.		X		X

* Indicates management contract or compensatory plan or arrangement

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

159

Signatures

DOMINION

Pursuant to the requirements of Section 13 or 15(d) 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.
By:	/S/    THOMAS F. FARRELL II
	(Thomas F. Farrell II, Chairman, President and Chief Executive Officer)

Date: February 28, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2013.

Signature	Title
/S/    THOMAS F. FARRELL II         Thomas F. Farrell II	Chairman of the Board of Directors, President and Chief Executive Officer
/S/    WILLIAM P. BARR         William P. Barr	Director
/S/    PETER W. BROWN         Peter W. Brown	Director
/S/    HELEN E. DRAGAS         Helen E. Dragas	Director
/S/    JOHN W. HARRIS         John W. Harris	Director
/S/    ROBERT S. JEPSON, JR.         Robert S. Jepson, Jr.	Director
/S/    MARK J. KINGTON         Mark J. Kington	Director
/S/    ROBERT H. SPILMAN, JR.         Robert H. Spilman, Jr.	Director
/S/    MICHAEL E. SZYMANCZYK         Michael E. Szymanczyk	Director
/S/    DAVID A. WOLLARD David A. Wollard	Director
/S/    MARK F. MCGETTRICK         Mark F. McGettrick	Executive Vice President and Chief Financial Officer
/S/    ASHWINI SAWHNEY         Ashwini Sawhney	Vice President—Accounting and Controller (Chief Accounting Officer)

160

VIRGINIA POWER

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VIRGINIA ELECTRIC AND POWER COMPANY
By:	/S/    THOMAS F. FARRELL II
	(Thomas F. Farrell II, Chairman of the Board of Directors and Chief Executive Officer)

Date: February 28, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2013.

Signature	Title
/S/    THOMAS F. FARRELL II         Thomas F. Farrell II	Chairman of the Board of Directors and Chief Executive Officer
/S/    MARK F. MCGETTRICK         Mark F. McGettrick	Director, Executive Vice President and Chief Financial Officer
/S/    ASHWINI SAWHNEY         Ashwini Sawhney	Vice President-Accounting (Chief Accounting Officer)
/S/    STEVEN A. ROGERS         Steven A. Rogers	Director

161

Exhibit Index

Exhibit Number	Description	Dominion		Virginia Power
2	Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1, Form 8-K filed March 15, 2010, File No. 1-8489).		X
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 December 13, 2011 (Exhibit 3.1, Form 8-K filed December 14, 2011, File No. 1-8489).		X
3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).				X
4	Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.		X		X
4.1.a	See Exhibit 3.1.a above.		X
4.1.b	See Exhibit 3.1.b above.				X
4.2	Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); Ninety-Second Supplemental Indenture, dated as of July 1, 2012 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2012 filed August 1, 2012, File No. 1-2255).		X		X
4.3	Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of First Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Eleventh Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255); Forms of Twelfth and Thirteenth Supplemental Indentures, dated January 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Forms of Sixteenth and Seventeenth Supplemental Indentures, dated November 1, 2007 (Exhibits 4.2 and 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255).		X		X
4.4	Indenture, Junior Subordinated Debentures, dated December 1, 1997, 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 supplemented by a First Supplemental Indenture, dated December 1, 1997		X

162

Exhibit Number	Description	Dominion		Virginia Power
	(Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement filed April 22, 1998, File No. 333-50653); Forms of Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits 4.6 and 4.13, Form 8-K filed January 12, 2001, File No. 1-8489).
4.5	Indenture, dated May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012); Fifteenth Supplemental Indenture, dated October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651); Seventeenth Supplemental Indenture, dated August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Eighteenth Supplemental Indenture, dated December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Nineteenth Supplemental Indenture, dated January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Twentieth Supplemental Indenture, dated March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-3196); Twenty-First Supplemental Indenture, dated June 27, 2007 (Exhibit 4.2, Form 8-K filed July 3, 2007, File No. 1-8489).		X
4.6	Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2, Form 8-A filed April 21, 1995, File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2, Form 8-A filed December 12, 1996, File No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2, Form 8-A filed October 22, 1998, File No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004); Second Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.4, Form 8-K filed July 3, 2007, File No. 1-8489).		X
4.7	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,		X

163

Exhibit Number	Description	Dominion		Virginia Power
	Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011(Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K, filed March 7, 2011, File No. 1-8489);Forty-Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 15, 2011, File No. 1-8489); Forty-Fifth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489).
4.8	Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K filed April 12, 2001, File No. 1-3196); Forms of Second and Third Supplemental Indentures, dated October 25, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed October 23, 2001, File No. 1-3196); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K filed May 22, 2002, File No. 1-3196); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196); Seventh Supplemental Indenture, dated June 27, 2007 (Exhibit 4.6, Form 8-K filed July 3, 2007, File No. 1-8489).		X
4.9	Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489).		X
4.10	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 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).		X
4.11	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 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2011 filed October 28, 2011, File No. 1-8489).		X

164

Exhibit Number	Description	Dominion		Virginia Power
4.12	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489).		X
10.1	DRS Services Agreement, dated January 1, 2003, between Dominion Resources, Inc. and Dominion Resources Services, Inc. (Exhibit 10.1, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489).		X
10.2	DRS Services Agreement, dated as of January 2012, between Dominion Resources Services, Inc. and Virginia Electric and Power Company (Exhibit 10.2, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255).				X
10.3	Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489).		X		X
10.4	$3.0 billion Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, JP Morgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., Barclays Capital, The Royal Bank of Scotland plc, and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein. (Exhibit 10.1, Form 8-K filed September 28, 2010, File No. 1-8489 and File No. 1-2255), as amended October 1, 2011 (Exhibit 10.1, Form 8-K filed October 3, 2011, File No. 1-8489 and File No. 1-2255).		X		X
10.5	$500 million Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, Keybank National Association, as Administrative Agent, Bayerische Landesbank, New York Branch, and U.S. Bank National Association, as Syndication Agents, and other lenders named therein. (Exhibit 10.2, Form 8-K filed September 28, 2010, File No. 1-8489 and File No. 1-2255), as amended October 1, 2011 (Exhibit 10.2, Form 8-K filed October 3, 2011, File No. 1-8489 and File No. 1-2255).		X		X
10.6	Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003 filed May 9, 2003, File No. 1-8489 and File No. 1-2255).		X		X
10.7*	Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X
10.8*	Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489), as amended June 20, 2007 (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489 and Exhibit 10.5, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-2255).		X		X
10.9*	Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 1-2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489).		X		X
10.10*	Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X
10.11*	Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X
10.12*	Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489), amended January 19, 2006 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2005 filed March 2, 2006, File No. 1-8489), as amended December 1, 2006 and further amended January 1, 2007 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2006, filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489).		X		X
10.13*	Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489), as amended January 1, 2007 (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File		X		X

165

Exhibit Number	Description	Dominion		Virginia Power
	No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255), as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255).
10.14*	Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489).		X
10.15*	Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).		X
10.16*	Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489).		X
10.17*	Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489).		X
10.18*	Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489 and File No. 1-2255).		X		X
10.19*	Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011 (Exhibit 10.22, Form 10-K filed February 28, 2011, File No. 1-8489).		X
10.20*	Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X
10.21*	Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).		X
10.22*	Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489).		X
10.23*	Supplemental retirement agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255).		X
10.24*	Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255).		X
10.25*	Form of Restricted Stock Grant under 2007 Long-Term Compensation Program approved March 30, 2007 (Exhibit 10.1, Form 8-K filed April 5, 2007, File No. 1-8489).		X		X
10.26*	Form of Restricted Stock Award Agreement under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.1, Form 8-K filed April 2, 2008, File No. 1-8489).		X		X

166

Exhibit Number	Description	Dominion		Virginia Power
10.27*	Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255).		X		X
10.28*	2009 Performance Grant Plan under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.1, Form 8-K filed January 29, 2009, File No. 1-8489).		X		X
10.29*	Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489).		X		X
10.30*	Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective December 20, 2011 (Exhibit 10.32, Form 10-K for the fiscal year ended December 31, 2011 filed February 28, 2012, File No. 1-8489 and File No. 1-2255).		X		X
10.31*	2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489).		X		X
10.32*	Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489).		X		X
10.33*	Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489).		X		X
10.34*	2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489).		X		X
10.35*	Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489).		X		X
10.36*	Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian under the 2005 Incentive Compensation Plan approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012, File No. 1-8489).		X		X
10.37*	2012 Performance Grant Plan under the 2012 Long-Term Incentive Program approved January 19, 2012 (Exhibit 10.1, Form 8-K filed January 20, 2012, File No. 1-8489).		X		X
10.38*	Form of Restricted Stock Award Agreement under the 2012 Long-term incentive Program approved January 19, 2012 (Exhibit 10.2, Form 8-K filed January 20, 2012, File No. 1-8489).		X		X
10.39*	2013 Performance Grant Plan under 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.1, Form 8-K filed January 25, 2013, File No. 1-8489).		X		X
10.40*	Form of Restricted Stock Award Agreement under the 2013 Long-term Incentive Program approved January 24, 2013 (Exhibit 10.2, Form 8-K filed January 25, 2013, File No. 1-8489).		X		X
10.41*	Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010 (Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489).		X		X
10.42*	Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).		X
10.43*	Non-employee directors’ annual compensation for Dominion Resources, Inc. (filed herewith).		X
12.a	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).		X
12.b	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).				X
12.c	Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).				X
21	Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith).		X		X
23	Consent of Deloitte & Touche LLP (filed herewith).		X		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

167

Exhibit Number	Description	Dominion		Virginia Power
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
99.1	Dominion Resources, Inc. Earnings Release Kit (furnished herewith).		X
99.2	Supplemental Summary of 2012 Operating Earnings (furnished herewith).		X
99.3	Towers Watson Energy Services Survey participants (filed herewith).				X
101^	The following financial statements from Dominion Resources, Inc. and Virginia Electric and Power Company Annual Report on Form 10-K for the year ended December 31, 2012, filed on February 28, 2013, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.		X		X

* Indicates management contract or compensatory plan or arrangement

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

168

EX-10.42

Exhibit 10.42

Dominion Resources, Inc.

2013 Base Salaries for Named Executive Officers*

The 2013 base salaries for Dominion’s named executive officers are as follows: Thomas F. Farrell II, Chairman, President and Chief Executive Officer—$1,355,274; Mark F. McGettrick, Executive Vice President and Chief Executive Officer—$718,028; Paul D. Koonce, Executive Vice President and Chief Executive Officer— Energy Infrastructure Group (Chief Executive Officer—Dominion Virginia Power)—$592,665; David A. Christian, Executive Vice President and Chief Executive Officer—Dominion Generation Group (Chief Executive Officer—Dominion Generation)—$625,500; and Gary L. Sypolt, Executive Vice President (Chief Executive Officer—Dominion Energy)—$531,753.

* Effective March 1, 2013

EX-10.43

Exhibit 10.43

Dominion Resources, Inc.

Non-Employee Directors’ Annual Compensation

As of December 31, 2012

Annual Retainer	Amount
Service as Director	$	170,000 ($70,000 cash; $100,000 stock	)
Service as Audit Committee or Compensation, Governance and Nominating Committee Chair	$	17,500
Service as Finance and Risk Oversight Committee Chair	$	10,000
Service as Lead Director	$	20,000
Meeting Fees
Board meetings	$	2,000 per meeting
Committee meetings	$	2,000 per meeting

EX-12.A

Exhibit 12.a

Dominion Resources Inc. and Subsidiaries

Computation of Ratio of Earnings to Fixed Charges

(millions of dollars)

	Years Ended December, 31
	2012 (a)			2011 (b)			2010 (c)			2009 (d)			2008 (e)
Earnings, as defined:
Income from continuing operations including noncontrolling interest before income taxes, extraordinary item and cumulative effect of change in accounting principle	$	497		$	2,205		$	5,195		$	1,900		$	2,539
Distributed income from unconsolidated investees, less equity in earnings		(13	)		(23	)		(30	)		(30	)		(39	)
Fixed charges, as defined		1,007			1,003			971			1,022			989
Capitalized interest		(37	)		(37	)		(27	)		(18	)		(44	)
Preference security dividend requirement of consolidated subsidiary		(23	)		(25	)		(28	)		(24	)		(26	)
Total earnings, as defined	$	1,431		$	3,123		$	6,081		$	2,850		$	3,419
Fixed charges, as defined:
Interest charges	$	948		$	928		$	886		$	941		$	910
Preference security dividend requirement of consolidated subsidiary		23			25			28			24			26
Rental interest factor		36			50			57			57			53
Total fixed charges, as defined	$	1,007		$	1,003		$	971		$	1,022		$	989
Ratio of Earnings to Fixed Charges		1.42			3.11			6.26			2.79			3.46

(a) Earnings for the twelve months ended December 31, 2012 include $2.1 billion of impairment and other charges related to management’s decisions to pursue the sale of Brayton Point and Kincaid and the planned shut-down of Kewaunee; $87 million of restoration costs associated with severe storms affecting our Dominion Virginia Power and Dominion North Carolina service territories; partially offset by a $36 million net gain related to our investments in nuclear decommissioning trust funds and $4 million net benefit 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, 2012.

(b) Earnings for the twelve months ended December 31, 2011 include $228 million of impairment charges related to electric utility generation assets; $96 million of restoration costs associated with Hurricane Irene; $57 million impairment of excess emission allowances resulting from a new EPA Air Pollution Rule; $31 million net charge in connection with the Virginia

Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2009 and 2010 test years; $21 million of earthquake related costs, largely related to inspections following the safe shutdown of reactors at our North Anna nuclear power station; and $45 million net charge related to other items; partially offset by $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 December 31, 2011.

(c) Earnings for the twelve months ended December 31, 2010 include $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 $331 million charge related to the workforce reduction program primarily reflecting severance pay and other benefits to affected employees and $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 $712 million charge for a partial refund of 2008 earnings and other amounts in connection with the settlement of Virginia Power’s 2009 rate case proceeding; $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; $31 million impairment charge related to an equity method investment; and $10 million net charge related to other items. Earnings for the period also include $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; $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 $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.

EX-12.B

Exhibit 12.b

Virginia Electric and Power Company

Computation of Ratio of Earnings to Fixed Charges

(millions of dollars)

	Years Ended December 31,
	2012		2011		2010		2009		2008
Earnings, as defined:
Income from continuing operations before income taxes, extraordinary item and cumulative effect of change in accounting principle	$	1,703	$	1,362	$	1,394	$	503	$	1,364
Fixed charges as defined		418		361		385		392		343
Capitalized interest		—		—		—		—		—
Total earnings, as defined	$	2,121	$	1,723	$	1,779	$	895	$	1,707
Fixed charges, as defined:
Interest charges	$	404	$	346	$	368	$	376	$	330
Rental interest factor		14		15		17		16		13
Total fixed charges, as defined	$	418	$	361	$	385	$	392	$	343
Ratio of Earnings to Fixed Charges		5.07		4.77		4.62		2.28		4.98

EX-12.C

Exhibit 12.c

Virginia Electric and Power Company

Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends

(millions of dollars)

	Years Ended December 31,
	2012			2011			2010			2009			2008
Earnings, as defined:
Income from continuing operations before income taxes, extraordinary item and cumulative effect of change in accounting principle	$	1,703		$	1,362		$	1,394		$	503		$	1,364
Fixed charges as defined		445			388			412			416			369
Capitalized interest		—			—			—			—			—
Preference security dividend requirement		(27	)		(27	)		(27	)		(24	)		(26	)
Total earnings, as defined	$	2,121		$	1,723		$	1,779		$	895		$	1,707
Fixed charges, as defined:
Interest charges	$	404		$	346		$	368		$	376		$	330
Preference security dividend requirement		27			27			27			24			26
Rental interest factor		14			15			17			16			13
Total fixed charges, as defined	$	445		$	388		$	412		$	416		$	369
Ratio of Earnings to Fixed Charges and Preferred Dividends		4.77			4.44			4.32			2.15			4.63

EX-21

Exhibit 21

Dominion Resources, Inc.

Subsidiaries of the Registrant

As of February 15, 2013

Name	Jurisdiction of Incorporation	Name Under Which Business is Conducted
Dominion Resources, Inc.	Virginia	Dominion Resources, Inc.
CNG Coal Company	Delaware	CNG Coal Company
Dominion Capital, Inc.	Virginia	Dominion Capital, Inc.
Dominion Cove Point, Inc.	Virginia	Dominion Cove Point, Inc.
Dominion Cove Point LNG Company, LLC	Delaware	Dominion Cove Point LNG Company, LLC
Dominion Gas Projects Company, LLC	Delaware	Dominion Gas Projects Company, LLC
Dominion Cove Point LNG, LP	Delaware	Dominion Cove Point LNG, LP
Dominion CNG Capital Trust I	Delaware	Dominion CNG Capital Trust I
Dominion Energy, Inc.	Virginia	Dominion Energy, Inc.
CNG Power Services Corporation	Delaware	CNG Power Services Corporation
Dominion Armstrong, LLC	Delaware	Dominion Armstrong, LLC
Dominion Bridgeport Fuel Cell, LLC	Virginia	Dominion Bridgeport Fuel Cell, LLC
Dominion Cogen WV, Inc.	Virginia	Dominion Cogen WV, Inc.
Dominion Elwood, Inc.	Delaware	Dominion Elwood, Inc.
Dominion Elwood Expansion, Inc.	Delaware	Dominion Elwood Expansion, Inc.
Dominion Elwood Services Company, Inc.	Virginia	Dominion Elwood Services Company, Inc.
Dominion Energy Marketing, Inc.	Delaware	Dominion Energy Marketing, Inc.
Dominion Nuclear Connecticut, Inc.	Delaware	Dominion Nuclear Connecticut, Inc.
Dominion Energy Brayton Point, LLC	Virginia	Dominion Energy Brayton Point, LLC
Dominion Energy Manchester Street, Inc.	Virginia	Dominion Energy Manchester Street, Inc.
Dominion Energy Services Company, Inc.	Virginia	Dominion Energy Services Company, Inc.
Dominion Energy Terminal Company, Inc.	Virginia	Dominion Energy Terminal Company, Inc.
Dominion Equipment, Inc.	Virginia	Dominion Equipment, Inc.
Dominion Equipment II, Inc.	Virginia	Dominion Equipment II, Inc.
Dominion Equipment III, Inc.	Delaware	Dominion Equipment III, Inc.
Dominion Fairless Hills, Inc.	Delaware	Dominion Fairless Hills, Inc.
Fairless Energy, LLC	Delaware	Fairless Energy, LLC
Dominion Kincaid, Inc.	Virginia	Dominion Kincaid, Inc.
Kincaid Generation, L.L.C.	Virginia	Kincaid Generation, L.L.C.
Dominion Mt. Storm Wind, LLC	Virginia	Dominion Mt. Storm Wind, LLC
Dominion North Star Generation, Inc.	Delaware	Dominion North Star Generation, Inc.
North Star Generation, LLC	Delaware	North Star Generation, LLC
Dominion Nuclear Projects, Inc.	Virginia	Dominion Nuclear Projects, Inc.
Dominion Energy Kewaunee, Inc.	Wisconsin	Dominion Energy Kewaunee, Inc.
Dominion Person, Inc.	Delaware	Dominion Person, Inc.
Dominion Solar Holdings, LLC	Virginia	Dominion Solar Holdings, LLC
Dominion State Line, LLC	Delaware	Dominion State Line, LLC
Dominion Wholesale, Inc.	Virginia	Dominion Wholesale, Inc.
Dominion Wind Projects, Inc.	Virginia	Dominion Wind Projects, Inc.
Prairie Fork Wind Farm, LLC	Virginia	Prairie Fork Wind Farm, LLC
Dominion Virginia Wind Development, LLC	Virginia	Dominion Virginia Wind Development, LLC
Dominion Fowler Ridge Wind, LLC	Virginia	Dominion Fowler Ridge Wind, LLC
Dominion Alternative Energy Holdings, Inc.	Virginia	Dominion Alternative Energy Holdings, Inc.
Dominion Energy Technologies, Inc.	Virginia	Dominion Energy Technologies, Inc.

Dominion Energy Technologies II, Inc.	Virginia	Dominion Energy Technologies II, Inc.
Dominion Voltage, Inc.	Virginia	Dominion Voltage, Inc.
Tredegar Solar Fund I, LLC	Delaware	Tredegar Solar Fund I, LLC
Dominion Field Services, Inc.	Delaware	Dominion Field Services, Inc.
Dominion Greenbrier, Inc.	Virginia	Dominion Greenbrier, Inc.
Greenbrier Pipeline Company, LLC	Delaware	Greenbrier Pipeline Company, LLC
Greenbrier Marketing Company, LLC	Delaware	Greenbrier Marketing Company, LLC
Dominion Investments, Inc.	Virginia	Dominion Investments, Inc.
Dominion Iroquois, Inc.	Delaware	Dominion Iroquois, Inc.
Dominion Keystone Pipeline Holdings, Inc.	Delaware	Dominion Keystone Pipeline Holdings, Inc.
Dominion Keystone Pipeline, LLC	Delaware	Dominion Keystone Pipeline, LLC
Dominion Oklahoma Texas Exploration & Production, Inc.	Delaware	Dominion Oklahoma Texas Exploration & Production, Inc.
Dominion Products and Services, Inc.	Delaware	Dominion Products and Services, Inc.
Dominion Resources Capital Trust I	Delaware	Dominion Resources Capital Trust I
Dominion Resources Capital Trust II	Delaware	Dominion Resources Capital Trust II
Dominion Resources Capital Trust III	Delaware	Dominion Resources Capital Trust III
Dominion Resources Capital Trust IV	Delaware	Dominion Resources Capital Trust IV
Dominion Resources Services, Inc.	Virginia	Dominion Resources Services, Inc.
Dominion Retail, Inc.	Delaware	Dominion Energy Solutions Dominion East Ohio Energy Dominion Peoples Plus
Cirro Group, Inc.	Texas	Cirro Group, Inc.
Cirro Energy Services, Inc.	Texas	Cirro Energy Services, Inc.
Dominion South Holdings I, Inc.	Delaware	Dominion South Holdings I, Inc.
Dominion South Holdings II, LLC	Delaware	Dominion South Holdings II, LLC
Dominion South Pipeline Company, LP	Delaware	Dominion South Pipeline Company, LP
Dominion Technical Solutions, Inc.	Virginia	Dominion Technical Solutions, Inc.
Dominion Transmission, Inc.	Delaware	Dominion Transmission, Inc.
Dominion Brine, LLC	Delaware	Dominion Brine, LLC
Tioga Properties, LLC	Delaware	Tioga Properties, LLC
Farmington Properties, Inc.	Pennsylvania	Farmington Properties, Inc.
NE Hub Partners, L.L.C.	Delaware	NE Hub Partners, L.L.C.
NE Hub Partners, L.P.	Delaware	NE Hub Partners, L.P.
Dominion Natrium Holdings, Inc.	Delaware	Dominion Natrium Holdings, Inc.
Dominion NGL Pipelines, LLC	Delaware	Dominion NGL Pipelines, LLC
Dominion Natrium, LLC	Delaware	Dominion Natrium, LLC
Dominion VPP Holdings, LLC	Delaware	Dominion VPP Holdings, LLC
Hope Gas, Inc.	West Virginia	Dominion Hope
The East Ohio Gas Company	Ohio	Dominion East Ohio
Virginia Electric and Power Company	Virginia	Dominion Virginia Power (in Virginia) Dominion North Carolina Power (in North Carolina)
Virginia Power Fuel Corporation	Virginia	Virginia Power Fuel Corporation
Virginia Power Services, LLC	Virginia	Virginia Power Services, LLC
Dominion Generation Corporation	Virginia	Dominion Generation Corporation
Virginia Power Services Energy Corp., Inc.	Virginia	Virginia Power Services Energy Corp., Inc.
Virginia Power Nuclear Services Company	Virginia	Virginia Power Nuclear Services Company
VP Property, Inc.	Virginia	VP Property, Inc.
Virginia Power Energy Marketing, Inc.	Virginia	Virginia Power Energy Marketing, Inc.

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-172941 and 333-179213 on Forms S-3, Registration Statement No. 333-120339 on Form S-4, and Registration Statement Nos. 333-163805, 333-149993, 333-156027, 333-124257, 333-124256, 333-149989, 333-25587, 333-78173, 333-49725, 333-18391, and 333-02733 on Forms S-8 of our reports dated February 27, 2013, relating to the consolidated financial statements of Dominion Resources, Inc. and subsidiaries and the effectiveness of Dominion Resources, Inc. and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Dominion Resources, Inc. for the year ended December 31, 2012.

We consent to the incorporation by reference in Registration Statement No. 333-178772 on Form S-3 of our report dated February 27, 2013, relating to the consolidated financial statements of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries, appearing in this Annual Report on Form 10-K of Virginia Electric and Power Company for the year ended December 31, 2012.

/s/Deloitte & Touche LLP

Richmond, Virginia

February 27, 2013

EX-31.A

Exhibit 31.a

I, Thomas F. Farrell II, certify that:

1. I have reviewed this report on Form 10-K 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: February 28, 2013	/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-K 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: February 28, 2013	/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-K 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: February 28, 2013	/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-K 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: February 28, 2013	/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 Annual Report on Form 10-K for the year ended December 31, 2012 (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 December 31, 2012 and for the period then ended.

/s/ Thomas F. Farrell II

Thomas F. Farrell II

President and Chief Executive Officer

February 28, 2013

/s/ Mark F. McGettrick

Mark F. McGettrick

Executive Vice President and Chief Financial Officer

February 28, 2013

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 Annual Report on Form 10-K for the year ended December 31, 2012 (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 December 31, 2012 and for the period then ended.

/s/ Thomas F. Farrell II

Thomas F. Farrell II

Chief Executive Officer

February 28, 2013

/s/ Mark F. McGettrick

Mark F. McGettrick

Executive Vice President and Chief Financial Officer

February 28, 2013

EX-99.1

Exhibit 99.1

Revised

4^th Quarter 2012

Earnings Release

Kit

February 28, 2013

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Table of Contents

IMPORTANT NOTES TO INVESTORS	3
EARNINGS REPORT AND ACCOMPANYING SCHEDULES	4
EARNINGS REPORT	4
SCHEDULE 1 - SEGMENT OPERATING EARNINGS	7
SCHEDULE 2 - RECONCILIATION OF 2012 OPERATING EARNINGS TO REPORTED EARNINGS	8
SCHEDULE 3 - RECONCILIATION OF 2011 ORIGINAL OPERATING EARNINGS TO REPORTED EARNINGS	9
SCHEDULE 4 - RECONCILIATION OF 2012 EARNINGS TO 2011	10
FINANCIALS	11
CONSOLIDATED FINANCIAL STATEMENTS (GAAP)	11
SEGMENT OPERATING EARNINGS RESULTS	14
OPERATING STATISTICS	20
2012 WEATHER VARIANCE	23
FINANCE & LIQUIDITY	24
SCHEDULE OF LONG-TERM DEBT	24
SCHEDULE OF DEBT MATURITIES	25
SCHEDULE OF LIQUIDITY POSITION	26
SCHEDULE OF CHANGE IN CAPITALIZATION	27
HEDGING	28
RECONCILIATION OF FORECAST AND OUTLOOK	29
RECONCILIATION OF OPERATING EARNINGS GUIDANCE	29
GAAP RECONCILIATION	31
RECONCILIATION OF 2012 CONSOLIDATED OPERATING EARNINGS TO REPORTED EARNINGS	31
RECONCILIATION OF 2011 CONSOLIDATED OPERATING EARNINGS TO REPORTED EARNINGS	32
RECONCILIATION OF 2012 CORPORATE AND OTHER OPERATING EARNINGS TO REPORTED EARNINGS	33
RECONCILIATION OF 2011 DOMINION GENERATION EARNINGS TO REPORTED EARNINGS	34
RECONCILIATION OF 2011 CORPORATE AND OTHER OPERATING EARNINGS TO REPORTED EARNINGS	35
RECONCILIATION OF 2012 OPERATING EARNINGS TO REPORTED EARNINGS	36
RECONCILIATION OF 2011 OPERATING EARNINGS TO REPORTED EARNINGS	37
RECONCILIATION OF 1Q12 AND 4Q12 OPERATING EARNINGS TO REPORTED EARNINGS	38
RECONCILIATION OF 4Q11 OPERATING EARNINGS TO REPORTED EARNINGS	39
2013 EARNINGS EXPECTATIONS	40
APPENDIX	41
LIST OF REVISED SCHEDULES	41

February 28, 2013 2

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Important Notes to Investors

This kit contains certain forward-looking statements, including forecasted operating earnings for first-quarter and full-year 2013 which are subject to various risks and uncertainties. Factors that could cause actual results to differ materially from management’s projections, forecasts, estimates and expectations may include factors that are beyond the company’s ability to control or estimate precisely, including fluctuations in energy-related commodity prices, estimates of future market conditions, additional competition in the electric industry, changes in the demand for Dominion’s services, access to and costs of capital, fluctuations in the value of our pension assets and assets held in our decommissioning trusts, asset portfolio reviews and resulting decisions to acquire, divest or retire assets, the receipt of regulatory approvals for, and timing of, planned projects, acquisitions and divestitures, and the ability to complete planned construction or expansion projects within the terms and timeframes initially anticipated. Other factors include, but are not limited to, weather conditions and other events, including the effects of hurricanes, earthquakes, high winds, major storms and changes in water temperatures on operations, the risk associated with the operation of nuclear facilities, unplanned outages of Dominion’s generation facilities, state and federal legislative and regulatory developments and changes to environmental and other laws and regulations, including those related to climate change, greenhouse gases and other emissions to which we are subject, political and economic conditions, industrial, commercial and residential growth or decline in Dominion’s service area, risks of operating businesses in regulated industries that are subject to changing regulatory structures, changes to regulated gas and electric rates collected by Dominion, changes to rating agency requirements and ratings, changing financial accounting standards, fluctuations in interest rates, changes in federal and state tax laws, employee workforce factors, including collective bargaining, counter-party credit and performance risks, adverse outcomes in litigation matters or regulatory proceedings, the risk of hostile cyber intrusions and other uncertainties. Other risk factors are detailed from time to time in Dominion’s most recent quarterly report on Form 10-Q or annual report on Form 10-K filed with the Securities and Exchange Commission.

Certain information provided in this Release Kit includes financial measures that are not required by, or presented in accordance with generally accepted accounting principles (GAAP), including operating earnings before interest and taxes (EBIT) and operating earnings before interest, taxes, depreciation and amortization (EBITDA). These non-GAAP financial measures should not be considered as alternatives to GAAP measures, such as net income, operating income, or earnings per share, and may be calculated differently from, and therefore may not be comparable to, similarly titled measures used at other companies. Dominion has included reconciliations to the most directly comparable financial measures it is able to calculate and report in accordance with GAAP.

The consolidated financial data and statistics in this Revised 4Q12 Earnings Release Kit and its individual components reflect the financial position and operating results of Dominion and its primary operating segments through December 31, 2012. Independent auditors have not audited any of the financial and operating statements. Projections or forecasts shown in this document are based on the assumptions listed in this document and are subject to change at any time. Dominion undertakes no obligation to update any forward-looking information statement to reflect developments after the statement is made.

This Revised 4Q12 Earnings Release Kit has been prepared primarily for securities analysts and investors in the hope that it will serve as a convenient and useful reference document. The format of this release kit may change in the future as we continue to try to meet the needs of securities analysts and investors. This release kit is not intended for use in connection with any sale, offer to sell, or solicitation of any offer to buy securities.

Please continue to check our website regularly at www.dom.com/investors for the most recent updates.

February 28, 2013 3

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Earnings Report and Accompanying Schedules

Earnings Report

SUMMARY OF DOMINION’S REVISED 2012 EARNINGS

As of February 28, 2013, Dominion’s reported earnings determined in accordance with Generally Accepted Accounting Principles (GAAP) for the 12 months ended Dec. 31, 2012, are $302 million ($0.53 per share), compared with reported earnings of $1.41 billion ($2.45 per share) for the same period in 2011.

Operating earnings for the 12 months ended Dec. 31, 2012, amounted to $1.75 billion ($3.05 per share), compared to originally reported operating earnings of $1.75 billion ($3.05 per share) for the same period in 2011. Operating earnings are defined as reported (GAAP) earnings adjusted for certain items.

Dominion uses operating earnings as the primary performance measurement of its earnings guidance and results for public communications with analysts and investors. Dominion also uses operating earnings internally for budgeting, for reporting to the Board of Directors, for the company’s incentive compensation plans and for its targeted dividend payouts and other purposes. Dominion management believes operating earnings provide a more meaningful representation of the company’s fundamental earnings power.

The principal difference between GAAP earnings and operating earnings for fourth-quarter 2012 was an impairment charge of $1.01 billion related to fossil fuel-fired generating stations, which are in the process of being sold.

Business segment results and detailed descriptions of items included in 2012 and 2011 reported earnings but excluded from operating earnings can be found on Schedules 1, 2 and 3 of this release kit.

Full-year 2012 operating earnings compared to 2011

Full-year 2012 operating earnings per share were the same as compared to originally reported full-year 2011 operating earnings per share. Positive factors for the year were higher contributions from unregulated retail energy marketing operations, lower operations and maintenance expenses, benefit from our contribution of assets to the Blue Racer Midstream joint venture, lower interest expenses and a lower effective tax rate. Negative factors for the year were milder-than-normal weather in our regulated electric service territory, lower merchant generation margins and lower contributions from producer services.

February 28, 2013 4

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Fourth-quarter 2012 operating earnings compared to 2011

The increase in fourth-quarter 2012 operating earnings per share as compared to originally reported fourth-quarter 2011 operating earnings per share is primarily attributable to lower operations and maintenance expenses and benefit from our contribution of assets to the Blue Racer Midstream joint venture. Negative factors for the quarter were lower contributions from unregulated retail energy marketing operations and an extended outage at Millstone Unit 2.

Details of fourth-quarter 2012 operating earnings as compared to 2011 can be found on Schedule 4 of this release kit.

First-quarter 2013 and full-year 2013 operating earnings guidance

Dominion expects first-quarter 2013 operating earnings in the range of 80 cents per share to 95 cents per share as compared to first-quarter 2012 operating earnings of 85 cents per share. Positive factors for the first-quarter of 2013 compared to the same period of the prior year include an expected return to normal weather in our electric service territory, higher rate adjustment clause revenues and anticipated growth in our electric service territory as well as higher revenues related to our gas transmission growth projects. Negative factors for the quarter include higher operations and maintenance expenses and a higher effective tax rate. GAAP earnings for the first quarter of 2012 were 86 cents per share. A reconciliation between operating and GAAP earnings for the first quarter of 2012 can be found on Schedule 2 of this release kit.

Amounts for 2011 have been recast to reflect results for State Line and Salem Harbor generating stations as discontinued operations. However, Dominion uses originally reported 2011 amounts prior to recast to calculate operating earnings growth targets as well as for comparison to 2012 and 2013 operating earnings and statistics.

In providing its first-quarter and full-year 2013 operating earnings guidance, the company notes that there could be differences between expected reported earnings and estimated operating earnings for matters such as, but not limited to, divestitures or changes in accounting principles. At this time, Dominion management is not able to estimate the aggregate impact, if any, of these items on reported earnings, other than those as set forth on Schedule 2 – Reconciliation of 2012 Operating Earnings to Reported Earnings on page 8 of the Revised 4Q12 Earnings Release Kit. Accordingly, the company is not able to provide a corresponding GAAP equivalent for its operating earnings guidance.

February 28, 2013 5

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Dominion is one of the nation’s largest producers and transporters of energy, with a portfolio of approximately 27,500 megawatts of generation, 11,000 miles of natural gas transmission, gathering and storage pipeline and 6,300 miles of electric transmission lines. Dominion operates the nation’s largest natural gas storage system with 947 billion cubic feet of storage capacity and serves retail energy customers in 15 states. For more information about Dominion, visit the company’s website at www.dom.com.

This release contains certain forward-looking statements, including forecasted operating earnings for first-quarter and full-year 2013 which are subject to various risks and uncertainties. Factors that could cause actual results to differ materially from management’s projections, forecasts, estimates and expectations may include factors that are beyond the company’s ability to control or estimate precisely, including fluctuations in energy-related commodity prices, estimates of future market conditions, additional competition in the electric industry, changes in the demand for Dominion’s services, access to and costs of capital, fluctuations in the value of our pension assets and assets held in our decommissioning trusts, asset portfolio reviews and resulting decisions to acquire, divest or retire assets, the receipt of regulatory approvals for, and timing of, planned projects, acquisitions and divestitures, and the ability to complete planned construction or expansion projects within the terms and timeframes initially anticipated. Other factors include, but are not limited to, weather conditions and other events, including the effects of hurricanes, earthquakes, high winds, major storms and changes in water temperatures on operations, the risk associated with the operation of nuclear facilities, unplanned outages of Dominion’s generation facilities, state and federal legislative and regulatory developments and changes to environmental and other laws and regulations, including those related to climate change, greenhouse gases and other emissions to which we are subject, political and economic conditions, industrial, commercial and residential growth or decline in Dominion’s service area, risks of operating businesses in regulated industries that are subject to changing regulatory structures, changes to regulated gas and electric rates collected by Dominion, changes to rating agency requirements and ratings, changing financial accounting standards, fluctuations in interest rates, changes in federal and state tax laws, employee workforce factors, including collective bargaining, counter-party credit and performance risks, adverse outcomes in litigation matters or regulatory proceedings, the risk of hostile cyber intrusions and other uncertainties. Other risk factors are detailed from time to time in Dominion’s most recent quarterly report on Form 10-Q or annual report on Form 10-K filed with the Securities and Exchange Commission.

###

February 28, 2013 6

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Schedule 1 – Segment Operating Earnings

Preliminary, Unaudited

(millions, except earnings per share)	Three months ended December 31,
	2012			2011*			Change
Earnings:
Dominion Virginia Power	$	131		$	112		$	19
Dominion Energy		189			153			36
Dominion Generation		137			117			20
Corporate and Other		(57	)		(48	)		(9	)
OPERATING EARNINGS	$	400		$	334		$	66
Items excluded from operating earnings 2, 3		(1,059	)		(133	)		(926	)
REPORTED EARNINGS 1	$	(659	)	$	201		$	(860	)
Common Shares Outstanding (average, diluted)		575.0			571.2
Earnings Per Share (EPS):
Dominion Virginia Power	$	0.23		$	0.20		$	0.03
Dominion Energy		0.33			0.27			0.06
Dominion Generation		0.23			0.20			0.03
Corporate and Other		(0.10	)		(0.09	)		(0.01	)
OPERATING EARNINGS	$	0.69		$	0.58		$	0.11
Items excluded from operating earnings 2		(1.84	)		(0.23	)		(1.61	)
REPORTED EARNINGS 1	$	(1.15	)	$	0.35		$	(1.50	)

(millions, except earnings per share)	Twelve months ended December 31,
	2012			2011*			Change
Earnings:
Dominion Virginia Power	$	559		$	501		$	58
Dominion Energy		551			521			30
Dominion Generation		874			1,003			(129	)
Corporate and Other		(235	)		(271	)		36
OPERATING EARNINGS	$	1,749		$	1,754		$	(5	)
Items excluded from operating earnings 2, 4		(1,447	)		(346	)		(1,101	)
REPORTED EARNINGS 1	$	302		$	1,408		$	(1,106	)
Common Shares Outstanding (average, diluted)		573.9			574.6
Earnings Per Share (EPS):
Dominion Virginia Power	$	0.98		$	0.87		$	0.11
Dominion Energy		0.96			0.91			0.05
Dominion Generation		1.52			1.74			(0.22	)
Corporate and Other		(0.41	)		(0.47	)		0.06
OPERATING EARNINGS	$	3.05		$	3.05		$	(0.00	)
Items excluded from operating earnings 2		(2.52	)		(0.60	)		(1.92	)
REPORTED EARNINGS 1	$	0.53		$	2.45		$	(1.92	)

1) Determined in accordance with Generally Accepted Accounting Principles (GAAP).

2) Items excluded from operating earnings are reported in Corporate and Other segment. Refer to Schedules 2 and 3 for details, or find “GAAP Reconciliation” on Dominion’s website at www.dom.com/investors.

3) Pre-tax amounts for the current period and the prior period are ($1.687) billion and ($255) million, respectively.

4) Pre-tax amounts for the current period and the prior period are ($2.283) billion and ($605) million, respectively.

* Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

February 28, 2013 7

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Schedule 2 – Reconciliation of 2012 Operating Earnings to Reported Earnings

2012 Earnings (Twelve months ended December 31, 2012)

The net effects of the following items, all shown on an after-tax basis, are included in 2012 reported earnings, but are excluded from operating earnings:

• $1.1 billion net loss, including an impairment charge, associated with certain fossil fuel-fired merchant power stations which Dominion decided to market for sale in the third quarter of 2012.

• $303 million net loss, including impairment charges, primarily resulting from the planned shutdown of our Kewaunee nuclear merchant power station.

• $53 million of restoration costs associated with severe storms affecting our Dominion Virginia Power and Dominion North Carolina Power service territories.

• $22 million net loss from discontinued operations of two merchant power stations (State Line and Salem Harbor) which were sold in 2012.

• $5 million net benefit related to other items.

(millions, except per share amounts)	1Q12		2Q12			3Q12			4Q12			YTD 2012  2
Operating earnings	$	486	$	337		$	526		$	400		$	1,749
Items excluded from operating earnings (after-tax):
Fossil fuel-fired merchant power stations							(45	)		(1,029	)		(1,074	)
Kewaunee power station		2		(18	)		(281	)		(6	)		(303	)
Severe storms				(45	)		3			(11	)		(53	)
Discontinued operations - State Line & Salem Harbor		1		(18	)		(5	)					(22	)
Other items		5		2			11			(13	)		5
Total items excluded from operating earnings (after-tax) 1		8		(79	)		(317	)		(1,059	)		(1,447	)
Reported net income	$	494	$	258		$	209		($	659	)	$	302
Common shares outstanding (average, diluted)		571.9		573.1			574.7			575.0			573.9
Operating earnings per share	$	0.85	$	0.59		$	0.92		$	0.69		$	3.05
Items excluded from operating earnings (after-tax)		0.01		(0.14	)		(0.56	)		(1.84	)		(2.52	)
Reported earnings per share	$	0.86	$	0.45		$	0.36		($	1.15	)	$	0.53

1) Pre-tax amounts for items excluded from operating earnings are reflected in the following table:

	1Q12		2Q12			3Q12			4Q12			YTD 2012
Items excluded from operating earnings:
Fossil fuel-fired merchant power stations							(34	)		(1,670	)		(1,704	)
Kewaunee power station		3		(26	)		(435	)		(9	)		(467	)
Severe storms				(74	)		5			(18	)		(87	)
Discontinued operations - State Line & Salem Harbor		2		(32	)		(19	)					(49	)
Other items		8		3			3			10			24
Total items excluded from operating earnings	$	13	($	129	)	($	480	)	($	1,687	)	($	2,283	)

2) YTD 2012 EPS may not equal sum of quarters due to share count differences.

February 28, 2013 8

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Schedule 3 – Reconciliation of 2011 Original Operating Earnings to Reported Earnings

2011 Earnings (Twelve months ended December 31, 2011) ³

The net effects of the following items, all shown on an after-tax basis, are included in 2011 reported earnings, but are excluded from operating earnings:

• $178 million of impairment charges related to certain utility ($139 million) and merchant ($39 million) coal-fired power stations.

• $59 million of restoration costs associated with Hurricane Irene.

• $39 million net loss from operations at our Kewaunee nuclear merchant power station.

• $34 million impairment of excess emission allowances resulting from a new EPA air pollution rule.

• $21 million of severance costs and other charges related to our State Line and Salem Harbor merchant power stations.

• $19 million net charge in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2009-2010 test years.

• $13 million of earthquake related costs, largely related to inspections following the safe shutdown of reactors at our North Anna nuclear power station.

• $14 million benefit related to litigation with the Department of Energy for spent nuclear fuel-related costs at Millstone nuclear power station.

• $3 million net benefit related to other items.

(millions, except per share amounts)	1Q11			2Q11			3Q11			4Q11			YTD 2011 2
Operating earnings	$	541		$	338		$	541		$	334		$	1,754
Items excluded from operating earnings (after-tax):
Impairment of generation assets		(39	)								(139	)		(178	)
Hurricane Irene costs								(74	)		15			(59	)
Kewaunee operations		(19	)		(1	)		(12	)		(7	)		(39	)
Emission allowances impairments								(34	)					(34	)
Charges related to State Line & Salem Harbor operations					(11	)		(10	)					(21	)
Impact of Virginia Power biennial review order											(19	)		(19	)
Earthquake costs								(13	)					(13	)
Recoverable spent nuclear fuel-related costs					14									14
Other items		(4	)		(4	)		(6	)		17			3
Total items excluded from operating earnings (after-tax) 1		(62	)		(2	)		(149	)		(133	)		(346	)
Reported net income	$	479		$	336		$	392		$	201		$	1,408
Common shares outstanding (average, diluted)		580.5			575.2			571.2			571.2			574.6
Operating earnings per share	$	0.93		$	0.59		$	0.95		$	0.58		$	3.05
Items excluded from operating earnings (after-tax)		(0.11	)		(0.01	)		(0.26	)		(0.23	)		(0.60	)
Reported earnings per share	$	0.82		$	0.58		$	0.69		$	0.35		$	2.45

¹⁾  Pre-tax amounts for items excluded from operating earnings are reflected in the following table:

	1Q11			2Q11			3Q11			4Q11			YTD 2011
Items excluded from operating earnings:
Impairment of generation assets		(55	)								(228	)		(283	)
Hurricane Irene costs								(121	)		25			(96	)
Kewaunee operations		(32	)		(5	)		(19	)		(10	)		(66	)
Emission allowances impairments								(57	)					(57	)
Charges related to State Line & Salem Harbor operations					(17	)		(16	)					(33	)
Impact of Virginia Power biennial review order											(31	)		(31	)
Earthquake costs								(21	)					(21	)
Recoverable spent nuclear fuel-related costs					24									24
Other items		6			(8	)		(29	)		(11	)		(42	)
Total items excluded from operating earnings	($	81	)	($	6	)	($	263	)	($	255	)	($	605	)

²⁾  YTD 2011 EPS may not equal sum of quarters due to share count differences.

³⁾  Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

February 28, 2013 9

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Schedule 4 – Reconciliation of 2012 Earnings to 2011

Preliminary, unaudited	Three Months Ended						Twelve Months Ended
(millions, except EPS)	December 31,						December 31,
	2012 vs. 20111						2012 vs. 20111
	Increase / (Decrease)						Increase / (Decrease)
Reconciling Items	Amount			EPS			Amount			EPS
Dominion Virginia Power
Regulated electric sales:
Weather	$	5		$	0.01		($	34	)	($	0.06	)
Other		9			0.01			28			0.05
FERC Transmission equity return		4			0.01			19			0.04
Retail energy marketing operations		(10	)		(0.02	)		35			0.06
Storm damage and service restoration		1			0.00			14			0.03
Other		10			0.02			(4	)		(0.01	)
Change in contribution to operating earnings	$	19		$	0.03		$	58		$	0.11
Dominion Energy
Gas Distribution weather	$	1		$	0.00		($	5	)	($	0.01	)
Gas Transmission margin		14			0.02			8			0.01
Producer Services margin		(5	)		(0.01	)		(13	)		(0.02	)
Blue Racer Midstream JV		43			0.08			43			0.08
Other		(17	)		(0.03	)		(3	)		(0.01	)
Change in contribution to operating earnings	$	36		$	0.06		$	30		$	0.05
Dominion Generation
Regulated electric sales:
Weather	$	10		$	0.02		($	78	)	($	0.14	)
Other		11			0.02			46			0.08
Merchant generation margin		(13	)		(0.02	)		(109	)		(0.19	)
Brayton Point, Kincaid and Elwood 2011 earnings		16			0.02			7			0.01
State Line and Salem Harbor 2011 earnings		(2	)		0.00			(35	)		(0.06	)
Rate adjustment clause equity return		10			0.02			17			0.03
PJM ancillary services		1			0.00			(27	)		(0.05	)
Net capacity expenses		2			0.00			19			0.04
Outage costs		(13	)		(0.02	)		8			0.01
Other		(2	)		(0.01	)		23			0.05
Change in contribution to operating earnings	$	20		$	0.03		($	129	)	($	0.22	)
Corporate and Other
Change in contribution to operating earnings	($	9	)	($	0.01	)	$	36		$	0.06
Change in consolidated operating earnings	$	66		$	0.11		($	5	)	$	0.00
Change in items excluded from operating earnings 2	($	926	)	($	1.61	)	($	1,101	)	($	1.92	)
Change in reported earnings (GAAP)	($	860	)	($	1.50	)	($	1,106	)	($	1.92	)

¹⁾ Reflects 2011 amounts prior to recast of operating results of State Line and Salem Harbor generating stations as discontinued operations.

²⁾ Refer to Schedules 2 and 3 for details of items excluded from operating earnings, or find “GAAP Reconciliation” on Dominion’s website at www.dom.com/investors.

February 28, 2013 10

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Financials

Consolidated Financial Statements (GAAP)

Dominion Resources, Inc.

Consolidated Statements of Income *

Unaudited (GAAP Based)

	Three Months Ended					Years Ended
	December 31,					December 31,
	2012			20111		2012			20111
	(millions, except per share amounts)
Operating Revenue	$	3,167		$	3,129	$	13,093		$	14,145
Operating Expenses
Electric fuel and other energy-related purchases		855			902		3,748			4,097
Purchased electric capacity		90			110		387			454
Purchased gas		359			422		1,177			1,764
Other operations and maintenance		2,319			935		4,868			3,322
Depreciation, depletion and amortization		304			283		1,186			1,066
Other taxes		132			137		571			548
Total operating expenses		4,059			2,789		11,937			11,251
Income from operations		(892	)		340		1,156			2,894
Other income		49			66		223			178
Interest and related charges		215			176		882			867
Income from continuing operations including noncontrolling interests before income taxes		(1,058	)		230		497			2,205
Income tax expense		(406	)		24		146			754
Income from continuing operations including noncontrolling interests		(652	)		206		351			1,451
Loss from discontinued operations (net of tax)		—			1		(22	)		(25	)
Net Income including noncontrolling interests	$	(652	)	$	207	$	329		$	1,426
Noncontrolling interests		7			6		27			18
Net Income attributable to Dominion	$	(659	)	$	201	$	302		$	1,408
Reported earnings per common share - diluted	$	(1.15	)	$	0.35	$	0.53		$	2.45
Average shares outstanding, diluted		575.0			571.2		573.9			574.6

* The notes contained in Dominion’s most recent quarterly report on Form 10-Q or annual report on Form 10-K are an integral part of the Consolidated Financial Statements.

1) Consolidated Statements of Income for the three months ended and year ended December 31, 2011 have been recast to reflect Salem Harbor and State Line as discontinued operations.

February 28, 2013 11

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Dominion Resouces, Inc.

Consolidated Balance Sheets *

Unaudited & Summarized

($ in Millions)

	At December 31,
	2012		2011
Assets
Current Assets	$	5,140	$	5,430
Investments		4,191		3,985
Property, Plant and Equipment, Net		30,773		29,670
Deferred Charges and Other Assets		6,734		6,529
Total Assets	$	46,838	$	45,614
Liabilities and Equity
Securities due within one year	$	1,363	$	1,479
Securities due within one year, VIE		860		—
Short-term debt		2,412		1,814
Other current liabilities		3,128		3,669
Total Current Liabilities		7,763		6,962
Long-Term Debt		16,851		17,394
Deferred Credits and Other Liabilities		11,342		9,498
Total Liabilities		35,956		33,854
Subsidiary Preferred Stock Not Subject To Mandatory Redemption		257		257
Common Shareholders’ Equity		10,568		11,446
Noncontrolling Interest		57		57
Total Equity		10,625		11,503
Total Liabilities and Equity	$	46,838	$	45,614

* The notes contained in Dominion’s most recent quarterly report on Form 10-Q or annual report on Form 10-K are an integral part of the Consolidated Financial Statements.

February 28, 2013 12

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Dominion Resources, Inc.

Consolidated Statements of Cash Flows *

Unaudited & Summarized

($ in Millions)

	Year Ended December 31,
	2012			2011
Operating Activities
Net Income including noncontrolling interests	$	329		$	1,426
Adjustments to reconcile net income to net cash provided by operating activities
Impairment of generation assets		2,089			283
Depreciation, depletion and amortization (including nuclear fuel)		1,443			1,288
Deferred income taxes and investment tax credits, net		246			756
Other adjustments		(396	)		(204	)
Changes in:
Accounts receivable		292			365
Inventories		33			(185	)
Deferred fuel and purchased gas costs, net		368			(3	)
Prepayments		(85	)
Accounts payable		(61	)		(413	)
Accrued interest, payroll and taxes		(12	)		(216	)
Other operating assets and liabilities		(109	)		(114	)
Net cash provided by operating activities		4,137			2,983
Investing Activities
Plant construction and other property additions		(4,145	)		(3,652	)
Restricted cash equivalents		108			259
Other		197			72
Net cash used in investing activities		(3,840	)		(3,321	)
Financing Activities
Issuance of short-term debt, net		598			429
Issuance of short-term notes		400
Issuance and remarketing of long-term debt		1,500			2,320
Repayment and repurchase of long-term debt		(1,675	)		(637	)
Issuance of common stock		265			38
Repurchase of common stock		—			(601	)
Common dividend payments		(1,209	)		(1,129	)
Other		(30	)		(42	)
Net cash provided by (used in) financing activities		(151	)		378
Increase in cash and cash equivalents		146			40
Cash and cash equivalents at beginning of period		102			62
Cash and cash equivalents at end of period	$	248		$	102

* The notes contained in Dominion’s most recent quarterly report on Form 10-Q or annual report on Form 10-K are an integral part of the Consolidated Financial Statements.

February 28, 2013 13

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Segment Operating Earnings Results

Dominion Consolidated3	Three Months Ended						Year Ended
Unaudited Summary of Operating results	December 31,						December 31,
($mm except per share amounts)	2012			20111			2012			20111
Operating Revenue	$	3,050		$	3,216		$	12,762		$	14,314
Operating Expenses
Electric fuel and other energy-related purchases		823			915			3,650			4,152
Purchased electric capacity		90			110			387			454
Purchased gas		359			403			1,177			1,745
Other operations and maintenance		578			717			2,446			2,849
Depreciation, depletion and amortization		288			282			1,148			1,068
Other taxes		126			137			551			545
Total operating expenses		2,264			2,564			9,359			10,813
Income from operations		786			652			3,403			3,501
Other income		37			56			159			176
Income including noncontrolling interests before interest and income taxes		823			708			3,562			3,677
Interest and related charges		194			223			832			901
Income including noncontrolling interests before income taxes		629			485			2,730			2,776
Income taxes		222			145			954			1,004
Income including noncontrolling interests		407			340			1,776			1,772
Noncontrolling interests		7			6			27			18
Operating Earnings	$	400		$	334		$	1,749		$	1,754
Operating Earnings Per Share	$	0.69		$	0.58		$	3.05		$	3.05
Items excluded from operating earnings (net of taxes)2		(1,059	)		(133	)		(1,447	)		(346	)
Reported Earnings	$	(659	)	$	201		$	302		$	1,408
Reported Earnings Per Common Share - Diluted		(1.15	)	$	0.35		$	0.53		$	2.45
Average shares outstanding, diluted		575.0			571.2			573.9			574.6

¹⁾ Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

²⁾ For additional detail on items excluded from operating earnings see the GAAP Reconciliation schedules on pages 31-35.

³⁾ Dominion Consolidated Income Statement reflects the impact of segment eliminations and adjustments.

February 28, 2013 14

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Dominion Virginia Power	Three Months Ended				Year Ended
Unaudited Summary of Operating results	December 31,				December 31,
($mm except per share amounts)	2012		2011		2012		2011
Operating Revenue	$	843	$	901	$	3,497	$	3,836
Operating Expenses
Electric fuel and other energy-related purchases		197		216		865		1,069
Purchased electric capacity		—		10		16		46
Purchased gas		147		166		456		648
Other operations and maintenance		124		163		576		620
Depreciation, depletion and amortization		102		96		402		374
Other taxes		33		33		144		142
Total operating expenses		603		684		2,459		2,899
Income from operations		240		217		1,038		937
Other income		17		15		67		75
Income including noncontrolling interests before interest and income taxes		257		232		1,105		1,012
Interest and related charges		42		44		187		185
Income including noncontrolling interests before income taxes		215		188		918		827
Income taxes		82		74		351		318
Income including noncontrolling interests		133		114		567		509
Noncontrolling interests		2		2		8		8
Operating Earnings Contribution	$	131	$	112	$	559	$	501
Operating Earnings Per Share Contribution	$	0.23	$	0.20	$	0.98	$	0.87
Average shares outstanding, diluted		575.0		571.2		573.9		574.6

February 28, 2013 15

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Dominion Energy	Three Months Ended				Year Ended
Unaudited Summary of Operating results	December 31,				December 31,
($mm except per share amounts)	2012		2011		2012		2011
Operating Revenue	$	764	$	775	$	2,743	$	3,121
Operating Expenses
Electric fuel and other energy-related purchases		17		6		42		18
Purchased electric capacity		—		—		—		—
Purchased gas		246		271		927		1,176
Other operations and maintenance		85		155		501		703
Depreciation, depletion and amortization		55		57		216		207
Other taxes		46		48		172		177
Total operating expenses		449		537		1,858		2,281
Income from operations		315		238		885		840
Other income		15		20		65		61
Income including noncontrolling interests before interest and income taxes		330		258		950		901
Interest and related charges		12		14		47		57
Income including noncontrolling interests before income taxes		318		244		903		844
Income taxes		129		91		352		323
Income including noncontrolling interests		189		153		551		521
Noncontrolling interests		—		—		—		—
Operating Earnings Contribution	$	189	$	153	$	551	$	521
Operating Earnings Per Share Contribution	$	0.33	$	0.27	$	0.96	$	0.91
Average shares outstanding, diluted		575.0		571.2		573.9		574.6

February 28, 2013 16

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Dominion Generation	Three Months Ended				Year Ended
Unaudited Summary of Operating results	December 31,				December 31,
($mm except per share amounts)	2012		20111		2012		20111
Operating Revenue	$	1,505	$	1,634	$	6,850	$	7,670
Operating Expenses
Electric fuel and other energy-related purchases		631		731		2,840		3,210
Purchased electric capacity		90		100		371		408
Purchased gas		—		—		—		—
Other operations and maintenance		375		420		1,398		1,617
Depreciation, depletion and amortization		123		122		500		459
Other taxes		47		55		214		204
Total operating expenses		1,266		1,428		5,323		5,898
Income from operations		239		206		1,527		1,772
Other income		18		24		53		61
Income including noncontrolling interests before interest and income taxes		257		230		1,580		1,833
Interest and related charges		39		56		208		219
Income including noncontrolling interests before income taxes		218		174		1,372		1,614
Income taxes		76		53		479		601
Income including noncontrolling interests		142		121		893		1,013
Noncontrolling interests		5		4		19		10
Operating Earnings Contribution	$	137	$	117	$	874	$	1,003
Operating Earnings Per Share Contribution	$	0.23	$	0.20	$	1.52	$	1.74
Average shares outstanding, diluted		575.0		571.2		573.9		574.6

¹⁾ Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

February 28, 2013 17

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Corporate and Other	Three Months Ended						Year Ended
Unaudited Summary of Operating Results	December 31,						December 31,
($mm except per share amounts)	2012			20111			2012			20111
Operating Revenue	$	148		$	149		$	584		$	585
Operating Expenses
Electric fuel and other energy-related purchases		—			—			—			—
Purchased electric capacity		—			—			—			—
Purchased gas		1			1			3			5
Other operations and maintenance		147			149			577			578
Depreciation, depletion and amortization		8			7			30			28
Other taxes		—			1			21			22
Total operating expenses		156			158			631			633
Income (loss) from operations		(8	)		(9	)		(47	)		(48	)
Other income		13			25			80			85
Income including noncontrolling interests before interest and income taxes		5			16			33			37
Interest and related charges		127			137			496			546
Income including noncontrolling interests before income taxes		(122	)		(121	)		(463	)		(509	)
Income taxes		(65	)		(73	)		(228	)		(238	)
Income including noncontrolling interests		(57	)		(48	)		(235	)		(271	)
Noncontrolling interests		—			—			—			—
Operating Earnings (Loss) Contribution	$	(57	)	$	(48	)	$	(235	)	$	(271	)
Operating Earnings (Loss) Per Share Contribution	$	(0.10	)	$	(0.09	)	$	(0.41	)	$	(0.47	)
Items excluded from operating earnings (net of taxes)2		(1,059	)		(133	)		(1,447	)		(346	)
Reported Earnings	$	(1,116	)	$	(181	)	$	(1,682	)	$	(617	)
Reported Earnings Per Common Share - Diluted	$	(1.94	)	$	(0.32	)	$	(2.93	)	$	(1.07	)
Average shares outstanding, diluted		575.0			571.2			573.9			574.6

¹⁾ Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

²⁾ For additional detail on items excluded from operating earnings see the GAAP Reconciliation schedules on pages 31-35.

February 28, 2013 18

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Dominion

Unaudited Operating Revenue Detail (GAAP Based)

(millions)

		Three Months Ended					Year Ended
		December 31,					December 31,
		2012		20111			2012		20111
Dominion Consolidated
Operating Revenue
Electric sales:	Regulated	$	1,607	$	1,520		$	7,102	$	7,114
	Nonregulated		620		635			2,742		3,100
Gas sales:	Regulated		84		79			250		287
	Nonregulated		331		415			1,071		1,635
Gas transportation and storage			394		355			1,401		1,506
Other			131		125			527		503
Total operating revenue		$	3,167	$	3,129		$	13,093	$	14,145
Dominion Virginia Power
Operating Revenue
Electric sales:	Regulated	$	420	$	411		$	1,783	$	1,730
	Nonregulated		227		259			1,054		1,210
Gas sales:	Regulated		—		—			—		—
	Nonregulated		169		187			534		719
Gas transportation and storage			—		1			4		4
Other			27		43			122		173
Total operating revenue		$	843	$	901		$	3,497	$	3,836
Dominion Energy
Operating Revenue
Gas sales:	Regulated		84		79			250		287
	Nonregulated		186		250			703		957
Gas transportation and storage			399		358			1,420		1,525
Other			95		88			370		352
Total operating revenue		$	764	$	775		$	2,743	$	3,121
Dominion Generation
Operating Revenue
Electric sales:	Regulated	$	1,187	$	1,191		$	5,319	$	5,478
	Nonregulated		304		379			1,472		1,891
Other			14		16			59		66
Total operating revenue		$	1,505	$	1,586		$	6,850	$	7,435
Corporate and Other
Operating Revenue
Electric sales:	Regulated	$	—	$	(82	)	$	—	$	(94	)
	Nonregulated		115		39			327		154
Gas sales:	Regulated		—		—			—		—
	Nonregulated		1		5			4		8
Gas transportation and storage			—		—			—		—
Other			149		148			584		583
Total operating revenue		$	265	$	110		$	915	$	651

¹⁾ Amounts have been recast to reflect the results of State Line and Salem Harbor generating stations as discontinued operations.

February 28, 2013 19

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Operating Statistics

	Three Months Ended December 31,					Twelve Months Ended December 31,
	2012		2011			2012		2011
Dominion Consolidated
Regulated Electric Sales Revenue ($mm)
Residential	$	707	$	685		$	3,212	$	3,251
Commercial		516		531			2,284		2,273
Industrial		109		115			481		474
Governmental		185		189			760		811
Regulated retail revenue		1,517		1,521			6,737		6,809
Wholesale - sales for resale		46		46			191		204
Other revenue		44		(47	)		174		101
Total	$	1,607	$	1,520		$	7,102	$	7,114
Dominion Virginia Power
Degree Days (Electric service area)
Cooling
Actual		53		30			1,787		1,899
Normal		43		46			1,587		1,557
Heating
Actual		1,248		1,052			2,955		3,354
Normal		1,306		1,318			3,622		3,619
Electric Delivery Customers (at period end)
Residential		2,197,763		2,178,321			2,197,763		2,178,321
Commercial		235,579		234,190			235,579		234,190
Industrial		502		528			502		528
Governmental		32,425		32,317			32,425		32,317
Total Retail		2,466,269		2,445,356			2,466,269		2,445,356
Wholesale - sales for resale		5		5			5		5
Total		2,466,274		2,445,361			2,466,274		2,445,361
Electricity Delivered (GWh)
Residential		6,802		6,394			29,174		30,769
Commercial		6,865		6,633			28,927		28,949
Industrial		1,875		1,860			7,849		7,960
Governmental		2,570		2,555			10,774		10,823
Total Retail		18,112		17,443			76,724		78,500
Wholesale - sales for resale		990		933			4,029		3,814
Total		19,102		18,375			80,753		82,315
Dominion Retail
Unregulated Energy Customer Accounts (Average)
Natural Gas		550,247		549,145			552,079		558,194
Electric		695,149		737,379			699,567		764,753
Products and Services		885,304		863,421			876,978		828,816
Total		2,130,700		2,149,944			2,128,624		2,151,763
Volumes Sold
Natural Gas (mmcf)		25,887		23,794			87,587		95,719
Electricity (MWh)		3,345,650		2,197,561			13,889,548		12,995,215

Note: Figures may not add due to rounding

February 28, 2013 20

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

	Three Months Ended December 31,				Twelve Months Ended December 31,
	2012		2011		2012		2011
Dominion Energy
Gas Distribution
Regulated Gas Revenue ($mm)
Gas sales revenue
Residential	$	63	$	66	$	194	$	246
Commercial		11		11		35		36
Industrial		1		1		3		2
Other		2		1		3		3
Total	$	77	$	79	$	235	$	287
Regulated Gas Transportation and Storage Revenue ($mm)
Gas transportation revenue
Residential	$	96	$	89	$	358	$	413
Commercial		34		31		117		155
Industrial		15		14		56		58
Other		—		1		2		3
Total transportation revenue		145		134		533		629
Storage revenue		4		4		16		15
Total	$	149	$	139	$	549	$	644
Degree Days
Heating
Actual		1,956		1,740		4,986		5,584
Normal		2,005		2,069		5,713		5,888
LDC Natural Gas Customers (Average)
Gas sales customers
Residential		242,634		253,184		239,946		245,698
Commercial		11,459		11,361		10,803		10,672
Industrial		31		30		30		27
Other		25		25		25		25
Total		254,149		264,600		250,804		256,422
Gas transportation customers
Residential		956,866		946,069		962,432		957,845
Commercial		79,954		79,540		80,475		80,613
Industrial		1,610		1,549		1,569		1,563
Total		1,038,430		1,027,158		1,044,476		1,040,021
Total LDC natural gas customers
Residential		1,199,500		1,199,253		1,202,378		1,203,543
Commercial		91,413		90,901		91,278		91,285
Industrial		1,641		1,579		1,599		1,590
Other		25		25		25		25
Total		1,292,579		1,291,758		1,295,280		1,296,443
LDC Natural Gas Delivery (mmcf)
Gas sales volume
Residential		7,369		7,327		21,621		25,377
Commercial		1,293		1,207		3,782		4,016
Industrial		128		109		444		374
Other		253		92		427		424
Total		9,044		8,735		26,273		30,191
Gas transportation volume
Residential		26,793		23,875		81,925		90,028
Commercial		15,001		13,655		47,697		52,849
Industrial		30,352		25,355		123,330		103,067
Other		1,503		2,000		5,632		7,098
Total		73,648		64,885		258,586		253,042
Total LDC natural gas throughput
Residential		34,162		31,202		103,546		115,405
Commercial		16,294		14,862		51,479		56,865
Industrial		30,480		25,464		123,774		103,441
Other		1,756		2,092		6,059		7,522
Total		82,692		73,620		284,859		283,233

Note: Figures may not add due to rounding

February 28, 2013 21

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

	Three Months Ended December 31,				Twelve Months Ended December 31,
	2012		2011		2012		2011
Dominion Energy
Gas Transmission
Natural Gas Liquids sales (million gallons)		44.7		48.2		182.4		176.2
Average Realized NGL Price with Hedging ($/gal)	$	1.33	$	1.49	$	1.34	$	1.46
Gas Shrinkage Cost ($mm)	$	16.2	$	18.8	$	60.1	$	73.0
Dominion Generation
Regulated Generation
Electricity Sold (GWh) to VP/NCP customers
Residential		6,802		6,394		29,174		30,769
Commercial		6,865		6,633		28,927		28,949
Industrial		1,875		1,860		7,849		7,960
Governmental		2,570		2,555		10,774		10,823
Total Retail		18,112		17,443		76,724		78,500
Wholesale - sales for resale		990		933		4,029		3,814
Total		19,102		18,375		80,753		82,315
Merchant Generation
Total Electric Sales (GWh)
NEPOOL Merchant Fleet 1		3,928		4,031		18,925		17,710
PJM Merchant Fleet 2		1,990		1,761		8,241		7,216

¹⁾ Comprised of Millstone and Manchester generating stations.

²⁾ Comprised of Fairless generating station.

Note: Figures may not add due to rounding

February 28, 2013 22

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

2012 Weather Variance

Dominion - Effect of weather compared to normal ¹

Pre-tax Impact ($millions)
Description	1Q12			2Q12			3Q12			4Q12			FY2012
Gas Distribution 2	($	8.3	)	($	1.3	)	$	0.7		($	0.6	)	($	9.5	)
Electric Distribution 3		(30.3	)		(15.2	)		(2.0	)		(17.5	)		(65.0	)
Electric Transmission 3		(0.3	)		(0.3	)		0.2			(0.2	)		(0.6	)
Utility Generation (VaP) 4		(61.0	)		(33.3	)		(5.2	)		(35.1	)		(134.6	)
Earnings Impact (pre-tax)	($	99.9	)	($	50.1	)	($	6.3	)	($	53.3	)	($	209.7	)
After-tax Impact ($millions)
Description	1Q12			2Q12			3Q12			4Q12			FY2012
Gas Distribution 2	($	5.4	)	($	0.9	)	$	0.5		($	0.3	)	($	6.1	)
Electric Distribution 3		(18.5	)		(9.3	)		(1.2	)		(10.7	)		(39.7	)
Electric Transmission 3		(0.2	)		(0.2	)		0.1			(0.1	)		(0.4	)
Utility Generation (VaP) 4		(37.2	)		(20.3	)		(3.2	)		(21.4	)		(82.1	)
Earnings Impact (after-tax)	($	61.3	)	($	30.7	)	($	3.8	)	($	32.5	)	($	128.3	)
Dominion - Effect of weather compared to prior period 1
Pre-tax Impact ($millions)
Description	1Q’12 v. ‘11			2Q’12 v. ‘11			3Q’12 v. ‘11			4Q’12 v. ‘11			FY ‘12 v. ‘11
Gas Distribution 2	($	10.0	)	($	0.6	)	$	0.6			2.2		($	7.8	)
Electric Distribution 3		(29.8	)		(16.3	)		(17.8	)		8.5			(55.4	)
Electric Transmission 3		(0.4	)		(0.2	)		(0.2	)		—			(0.8	)
Utility Generation (VaP) 4		(60.5	)		(37.0	)		(46.8	)		16.2			(128.1	)
Earnings Impact (pre-tax)	($	100.7	)	($	54.1	)	($	64.2	)	$	26.9		($	192.1	)
After-tax Impact ($millions)
Description	1Q’12 v. ‘11			2Q’12 v. ‘11			3Q’12 v. ‘11			4Q’12 v. ‘11			FY ‘12 v. ‘11
Gas Distribution 2	($	6.3	)	($	0.4	)	$	0.4			1.4		($	4.9	)
Electric Distribution 3		(18.2	)		(9.9	)		(10.9	)		5.2			(33.8	)
Electric Transmission 3		(0.2	)		(0.1	)		(0.1	)		—			(0.4	)
Utility Generation (VaP) 4		(36.9	)		(22.6	)		(28.5	)		9.9			(78.1	)
Earnings Impact (after-tax)	($	61.6	)	($	33.0	)	($	39.1	)	$	16.5		($	117.2	)

1) The effects on earnings from differences in weather compared to normal and compared to prior periods are measured using base rate revenue. This schedule does not reflect the O&M expenditures for restoring service associated with outages caused by major storms.

2) Reported in the Dominion Energy segment. Comprised of Dominion East Ohio Gas Company and Hope Gas, Inc.

3) Reported in the Dominion Virginia Power segment.

4) Reported in the Dominion Generation segment.

Note: Figures may not add due to rounding

February 28, 2013 23

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Finance & Liquidity

Schedule of Long-Term Debt

Preliminary & Unaudited ($ in millions)

	At 12/31 2011			At 3/31 2012			At 6/30 2012			At 9/30 2012			At 12/31 2012
Dominion Resources, Inc.
Unsecured Senior Notes:
Variable rate, due 2013	$	—		$	—		$	—		$	—		$	400
1.4% to 7.195%, due 2012 to 2017 1	$	3,545		$	3,545		$	3,545		$	3,041		$	3,041
2.75% to 8.875%, due 2018 to 2042	$	4,399		$	4,399		$	4,399		$	5,099		$	5,099
Unsecured Debentures and Senior Notes (previously issued by CNG):
5.0% and 6.625%, due 2013 and 2014	$	622		$	622		$	622		$	622		$	622
6.8% and 6.875%, due 2026 and 2027	$	89		$	89		$	89		$	89		$	89
Unsecured Convertible Senior Notes, 2.125%, due 2023 2	$	143		$	137		$	82		$	82		$	82
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031 3	$	268		$	268		$	268		$	268		$	268
Enhanced Junior Subordinated Notes:
7.5% and 8.375%, due 2064 and 2066	$	985		$	985		$	985		$	985		$	985
Variable rate, due 2066 4	$	468		$	382		$	380		$	380		$	380
Virginia Electric and Power Company
Unsecured Senior Notes:
4.75% to 8.625%, due 2012 to 2017	$	2,321		$	2,319		$	2,313		$	2,311		$	1,706
2.95% to 8.875%, due 2018 to 2038	$	3,558		$	4,008		$	4,008		$	4,008		$	4,008
Tax-Exempt Financings:
Variable rates, due 2016 to 2041	$	454		$	454		$	454		$	454		$	454
1.5% to 6.5%, due 2017 to 2040 5	$	533		$	533		$	533		$	533		$	508
Dominion Energy, Inc.
Secured Senior Notes:
5.03% to 5.78%, due 2013	$	842		$	842		$	842		$	842		$	842
7.33%, due 2020	$	159		$	159		$	152		$	152		$	145
Tax-Exempt Financings:
2.25% to 5.75%, due 2033 to 2042	$	284		$	284		$	284		$	284		$	284
Variable rate, due 2041	$	75		$	75		$	75		$	75		$	75
Total Principal Amount	$	18,745		$	19,101		$	19,031		$	19,225		$	18,988
Fair Value Hedge Valuation		105			93			103			93			93
Amounts Due Within One Year		(1,479	)		(2,131	)		(2,141	)		(2,175	)		(2,223	)
Unamortized Discount & Premium, net		23			16			10			1			(7	)
Total Long-Term Debt	$	17,394		$	17,079		$	17,003		$	17,144		$	16,851

¹⁾  $334 million of Dominion’s 6.25% 2002 Series B Senior Notes matured June 30, 2012 but remained on the second quarter balance sheet because the corresponding cash flow did not occur until the next succeeding business day which was in the third quarter of 2012.

²⁾  $6 million and $55 million of the Convertible Senior Notes were converted into cash and common stock during first and second quarters of 2012, respectively.

³⁾  The $258 million 7.83% Junior Subordinated Notes due 2027 were redeemed early on January 3, 2013.

⁴⁾  $88 million of the 2006 Series B Enhanced Junior Subordinated Notes due 2066 were purchased and cancelled during the first and second quarters of 2012 primarily as a result of a tender offer.

⁵⁾  In October 2012, Virginia Power redeemed the $25 million 6.5% IDA of Mecklenburg County, Virginia Exempt Facility Revenue Refunding Bonds, Series 2002, that would have otherwise matured in October 2017.

February 28, 2013 24

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Schedule of Debt Maturities

As of December 31, 2012 (in $ millions)

	Due Date	DRI		VEPCO		Other		Total
2013
7.83% Jr Subordinated NP to Affiliated Trusts (Early Redemption)	01/03/13		257.7		—		—		257.7
4.75% 2003 Series A Senior Notes	03/01/13		—		400.0		—		400.0
5.0% 2003 Series D Senior Notes	03/15/13		250.0		—		—		250.0
5.03% to 5.78% 2004 Sr Secured Notes (from Juniper Consolidation)	08/15/13		—		—		841.6		841.6
2012 Private Placement Short Term Notes (variable)	11/21/13		400.0		—		—		400.0
6.625% 1993 Series B Debentures (from CNG Merger)	12/01/13		22.0		—		—		22.0
7.25% Mecklenburg Senior Bonds	multiple		—		11.6		—		11.6
8.625% Panda-Rosemary Senior Notes	multiple		—		5.9		—		5.9
7.33% Senior Secured Bonds	multiple		—		—		10.9		10.9
7.25% Ft Story, Ft Eustis, Ft Lee and Ft Monroe Promissory Notes	multiple		—		0.2		—		0.2
Total 2013			929.7		417.7		852.5		2,199.9
2014
5.0% 2003 Series A Senior Notes (from CNG Merger)	03/01/14		200.0		—		—		200.0
1.8% 2011 Series B Senior Notes	03/15/14		400.0		—		—		400.0
7.195% Remarketed 2000 Series E Senior Notes	09/15/14		47.3		—		—		47.3
5.0% 2004 Series A Senior Notes (from CNG Merger)	12/01/14		400.0		—		—		400.0
7.25% Mecklenburg Senior Bonds	multiple		—		11.2		—		11.2
8.625% Panda-Rosemary Senior Notes	multiple		—		6.1		—		6.1
7.33% Senior Secured Bonds	multiple		—		—		14.9		14.9
7.25% Ft Story, Ft Eustis, Ft Lee and Ft Monroe Promissory Notes	multiple		—		0.3		—		0.3
Total 2014			1,047.3		17.6		14.9		1,079.8
2015
5.15% 2005 Series C Senior Notes	07/15/15		500.0		—		—		500.0
2.25% 2010 Series A Senior Notes	09/01/15		250.0		—		—		250.0
5.25% 2003 Series C Senior Notes	12/15/15		—		200.0		—		200.0
7.25% Mecklenburg Senior Bonds	multiple		—		4.2		—		4.2
8.625% Panda-Rosemary Senior Notes	multiple		—		6.1		—		6.1
7.33% Senior Secured Bonds	multiple		—		—		17.7		17.7
7.25% Ft Story, Ft Eustis, Ft Lee and Ft Monroe Promissory Notes	multiple		—		0.3		—		0.3
Total 2015			750.0		210.6		17.7		978.3
2016
5.2% 2004 Series A Senior Notes	01/15/16		193.9		—		—		193.9
5.4% 2006 Series A Senior Notes	01/15/16		—		450.0		—		450.0
8.625% Panda-Rosemary Senior Notes	02/15/16		—		1.5		—		1.5
1986 Series IDA Prince William (variable)	08/01/16		—		11.2		—		11.2
1986 Series Grant County (variable)	08/01/16		—		7.4		—		7.4
1.95% 2011 Series D Senior Notes	08/15/16		450.0		—		—		450.0
5.6% 2006 Series A Senior Notes	11/15/16		250.0		—		—		250.0
7.25% Mecklenburg Senior Bonds	multiple		—		6.0		—		6.0
7.33% Senior Secured Bonds	multiple		—		—		19.9		19.9
7.25% Ft Story, Ft Eustis, Ft Lee and Ft Monroe Promissory Notes	multiple		—		0.3		—		0.3
Total 2016			893.9		476.4		19.9		1,390.2
2017
2011 Series A EDA Chesterfield County (variable)	06/01/17		—		75.0		—		75.0
1.4% 2012 Series A Senior Notes	09/15/17		350.0		—		—		350.0
5.95% 2007 Series B Senior Notes	09/15/07		—		600.0		—		600.0
6.0% 2007 Series A Senior Notes	11/30/17		350.0		—		—		350.0
7.25% Mecklenburg Senior Bonds	multiple		—		3.4		—		3.4
7.33% Senior Secured Bonds	multiple		—		—		21.5		21.5
7.25% Ft Story, Ft Eustis, Ft Lee and Ft Monroe Promissory Notes	multiple		—		0.3		—		0.3
Total 2017			700.0		678.7		21.5		1,400.2
Total 5-year Debt Maturities		$	4,320.9	$	1,801.0	$	926.5	$	7,048.4

February 28, 2013 25

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Schedule of Liquidity Position

As of December 31, 2012 (in $ millions)

Total Committed Bank Lines	$	3,500
Less:
Commercial Paper Outstanding	$	2,412
Letters of Credit Issued	$	26
Funded Loans	$	—
Total Available Capacity	$	1,062
Cash & Short-Term Investments On Hand*	$	197
Total Liquidity Available	$	1,259

* Represents aggregate collected cash balances; not ledger balances per financial statements, which totaled $248 million at 12/31/2012.

Committed bank lines consist of the following:

A $3.0 billion revolving credit facility entered into by Dominion Resources, Inc. (“DRI”) and Virginia Electric and Power Company (“VEPCO”) in September 2010 which will mature in September 2017. This facility is available to DRI as well as VEPCO.

A $500 million revolving credit facility entered into by DRI and VEPCO in September 2010. $100 million of capacity under this facility will mature in September 2016 and the remaining $400 million will mature in September 2017. This facility is available to DRI as well as VEPCO.

Additionally, there is a $120 million revolving credit facility (not reflected in table above) entered into by VEPCO in September 2010, which will mature in September 2017. This facility is dedicated to certain tax-exempt bond issuances by VEPCO.

February 28, 2013 26

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Schedule of Change in Capitalization

Dominion Resources, Inc & Subsidiaries

Summary of Changes in Capitalization From December 31, 2011 to December 31, 2012

($ in Millions)

Change in Debt (Long-Term Debt plus Securities Due Within One Year)
Balance as of December 31, 2011					$	18,873
Issuances:
VEPCO 2012 Series A 2.95% Senior Notes due 2022			450
DRI 2012 Series A 1.4% Senior Notes due 2017			350
DRI 2012 Series B 2.75% Senior Notes due 2022			350
DRI 2012 Series C 4.05% Senior Notes due 2042			350
DRI 2012 Private Placement (variable) Short Term Notes due 2013			400
			1,900
Maturities:
VEPCO 2007 Series C 5.1% Senior Notes due 2012			(600	)
DRI 2002 Series C 5.7% Senior Notes due 2012			(520	)
DRI 2002 Series B 6.25% Senior Notes due 2012			(334	)
DRI 2006 Series B (variable) Enhanced Jr Subordinated Notes due 20661			(88	)
DRI 2004 Series C 2.125% Unsecured Convertible Senior Notes due 20232			(61	)
VEPCO 2002 Series 6.5% IDA Mecklenburg Bonds due 20173			(25	)
Other			(29	)
			(1,657	)
Other:
Change in Fair Value Hedges and Net Discount/Premium			(42	)
			(42	)
Balance as of December 31, 2012					$	19,074
Change in Shareholders’ Equity
Balance as of December 31, 2011					$	11,503
Issuance of Common Stock, Net			313
Change in Other Paid-in Capital			(17	)
Changes in AOCI:
Net Other Comprehensive Gain (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:
Interest Rate	(49	)
Electricity	(78	)
Gas	5
NGL	54
	(68	)
Other changes in Net Other Comprehensive Income (4)	(199	)
Net change in AOCI			(267	)
Change in Retained Earnings			(907	)
Net change in Shareholders’ Equity						(878	)
Noncontrolling Interest						—
Net change in Equity						(878	)
Balance as of December 31, 2012					$	10,625

1) $88 million of the 2006 Series B Enhanced Junior Subordinated Notes due 2066 were purchased and cancelled primarily as a result of a tender offer.

2) $61 million of the Convertible Senior Notes were converted into cash and common stock.

3) Redeemed early on October 15, 2012.

4) Primarily reflects a net increase in unrealized gains on investments held in nuclear decommissioning trusts, and changes related to pension and OPEB benefit plans.

February 28, 2013 27

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Hedging

Power, Capacity and NGL Hedge Positions			As of January 31, 2013
Merchant Generation Power & Fuel	Net Summer Capacity  (MW)		2013			2014			2015
Hedge Positions 1
Millstone		2,016		82	%		59	%		37	%
Manchester		432		0	%		0	%		0	%
Fairless		1,196		0	%		0	%		0	%
Total Merchant Generation 2		3,644		45	%		32	%		21	%
Power Pricing
NEPOOL Baseload - Average Hedge Price ($/MWh) 3			$	48.83		$	49.01		$	54.29
Merchant Generation Capacity (EFOR Adjusted)			2013			2014			2015
Millstone & Manchester (MW)				2,473			2,467			2,469
Average Capacity Hedge Price ($/KW - month)			$	2.61		$	2.75		$	3.05
Fairless (MW) 4				1,181			1,178			1,183
Average Capacity Hedge Price ($/KW - month)			$	6.11		$	5.52		$	4.70
NGL			2013			2014
Estimated annual NGL sales (in million gallons) 5				140-150			120-130
Amount hedged (in million gallons)				127			116
Average hedge price per gallon 6			$	1.34		$	1.31

1) 2013 hedge percentages are calculated based on the weighted-average of: 1) actual results which are considered to be 100% hedged, and 2) balance of year hedge percentages. Capacity shown is net summer capacity. Assume capacity remains constant in all periods shown.

2) Annual percentage calculations are capacity-weighted. Excludes Wind assets.

3) NEPOOL Baseload Average Hedge Price includes all on-peak, off-peak, around-the-clock, and seasonal hedges for Millstone Power Station.

4) For the June 1, 2012 to December 31, 2015 period, Fairless RPM auction clearing price is based on Eastern MAAC LDA.

5) Represents Dominion’s production interest from the Hastings plant. A small portion of anticipated volumes from Natrium are included in 2013 for the period before the plant is contributed to the Blue Racer Midstream JV.

6) Average hedge price is based on a basket of liquids products: propane (52%), normal butane (17%), iso-butane (10%) and natural gasoline (21%).

February 28, 2013 28

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Reconciliation of Forecast and Outlook

Reconciliation of Operating Earnings Guidance

4Q12 Operating Earnings Summary

(millions, except per share amounts)

	4Q111			Range of 4Q12						4Q12
Description	Actual*			Low			High			Actual*
Operating Earnings before Interest and Taxes:
Dominion Virginia Power	$	232		$	280		$	305		$	257
Dominion Energy		258			265			295			330
Dominion Generation		230			260			285			257
Corporate and Other & Eliminations Adjusted EBIT		(12	)		(15	)		(5	)		(21	)
Total Adjusted EBIT		708			790			880			823
Consolidated Interest		223			205			195			194
Consolidated Income Taxes		145			215			245			222
Noncontrolling Interests		6			5			5			7
Operating Earnings	$	334		$	365		$	435		$	400
Average Diluted Shares Outstanding		571.2			577			575			575.0
Operating EPS Range	$	0.58		$	0.64		$	0.76		$	0.69
4Q12 Operating EPS Guidance Range*				$	0.65		$	0.75
Note: Figures may not add due to rounding		4Q12 Operating EPS Actual >>>								$	0.69

1) Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

* For information on items excluded from operating earnings see the GAAP Reconciliations on pages 36-39.

February 28, 2013 29

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

2012 Operating Earnings Summary

Dominion

2012 Operating Earnings Guidance Summary

(millions, except per share amounts)

	20111			Range of 2012						2012
Description	Actual*			Low			High			Actual*
Operating Earnings before Interest and Taxes:
Dominion Virginia Power	$	1,012		$	1,045		$	1,095		$	1,105
Dominion Energy		901			945			990			950
Dominion Generation		1,833			1,800			1,910			1,580
Corporate and Other & Eliminations Adjusted EBIT		(69	)		(75	)		(65	)		(73	)
Total Adjusted EBIT		3,677			3,715			3,930			3,562
Consolidated Interest		901			885			855			832
Consolidated Income Taxes		1,004			1,060			1,105			954
Noncontrolling Interests		18			25			25			27
Operating Earnings	$	1,754		$	1,745		$	1,945		$	1,749
Average Diluted Shares Outstanding		574.6			575			573			573.9
Operating EPS Range	$	3.05		$	3.03		$	3.39		$	3.05
2012 Operating EPS Guidance Range				$	3.10		$	3.35
Note: Figures may not add due to rounding		2012 Operating EPS Actual >>>								$	3.05

1) Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

* For information on items excluded from operating earnings see the GAAP Reconciliations on pages 36-39.

February 28, 2013 30

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

GAAP Reconciliation

Reconciliation of 2012 Consolidated Operating Earnings to Reported Earnings

Dominion Consolidated

Unaudited Income Statements

(millions, except per share amounts)

	Three Months Ended December 31, 2012								Twelve Months Ended December 31, 2012
	Operating		Adjustments			GAAP			Operating		Adjustments			GAAP
Operating Revenue	$	3,050	$	117	(a), (f)	$	3,167		$	12,762	$	331	(a), (f)	$	13,093
Operating Expenses
Electric fuel and other energy-related purchases		823		32	(a), (f)		855			3,650		98	(a), (f)		3,748
Purchased electric capacity		90		—			90			387		—			387
Purchased gas		359		—			359			1,177		—			1,177
Other operations and maintenance		578		1,741	(a), (e), (f), (g)		2,319			2,446		2,422	(a), (e), (f), (g)		4,868
Depreciation, depletion and amortization		288		16	(a), (f)		304			1,148		38	(a), (f)		1,186
Other taxes		126		6	(a), (f)		132			551		20	(a), (f)		571
Total operating expenses		2,264		1,795			4,059			9,359		2,578			11,937
Income from operations		786		(1,678	)		(892	)		3,403		(2,247	)		1,156
Other income (loss)		37		12	(a), (b), (f)		49			159		64	(a), (b), (f)		223
Income including noncontrolling interests before interest and income taxes		823		(1,666	)		(843	)		3,562		(2,183	)		1,379
Interest and related charges		194		21	(a), (f)		215			832		50	(a), (f)		882
Income including noncontrolling interests before income taxes		629		(1,687	)		(1,058	)		2,730		(2,233	)		497
Income taxes		222		(628	) (c)		(406	)		954		(808	) (c)		146
Income from continuing operations including noncontrolling interests		407		(1,059	)		(652	)		1,776		(1,425	)		351
Income (loss) from discontinued operations, net of tax		—		—			—			—		(22	) (d)		(22	)
Noncontrolling interests		7		—			7			27		—			27
Earnings	$	400	$	(1,059	)	$	(659	)	$	1,749	$	(1,447	)	$	302
Earnings Per Share - Diluted	$	0.69	$	(1.84	)	$	(1.15	)	$	3.05	$	(2.52	)	$	0.53
Average shares outstanding, diluted		575.0					575.0			573.9					573.9

Adjustments to Operating Earnings:

(a) Items related to Kewaunee nuclear merchant power station.

(b) Net gain/loss related to our investment in nuclear decommissioning trust funds.

(c) Income tax effects for items excluded from operating results.

(d) Items related to income/loss from State Line and Salem Harbor discontinued operations.

(e) Restoration costs associated with severe storms affecting our Dominion Virginia Power and Dominion North Carolina Power service territories.

(f) Items related to certain fossil fuel-fired merchant power stations, which Dominion decided to market for sale in the third quarter of 2012.

(g) Other miscellaneous items.

Note: Figures may not add due to rounding

February 28, 2013 31

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Reconciliation of 2011 Consolidated Operating Earnings to Reported Earnings

Dominion Consolidated

Unaudited Income Statements

(millions, except per share amounts)

	Three Months Ended December 31, 2011							Twelve Months Ended December 31, 2011
	Operating1		Adjustments			GAAP2		Operating1		Adjustments			GAAP2
Operating Revenue	$	3,216	$	(87	) (a), (b), (k),  (l)	$	3,129	$	14,314	$	(169	) (a), (b), (e),  (g), (k), (l)	$	14,145
Operating Expenses
Electric fuel and other energy-related purchases		915		(13	) (a), (b)		902		4,152		(55	) (a), (b), (e)		4,097
Purchased electric capacity		110		—			110		454		—			454
Purchased gas		403		19	(l)		422		1,745		19	(l)		1,764
Other operations and maintenance		717		218	(a), (b), (h),  (l), (m)		935		2,849		473	(a), (b), (f),  (h), (i), (j), (l), (m)		3,322
Depreciation, depletion and amortization		282		1	(a)		283		1,068		(2	) (a), (b), (f)		1,066
Other taxes		137		—			137		545		3	(a), (b)		548
Total operating expenses		2,564		225			2,789		10,813		438			11,251
Income from operations		652		(312	)		340		3,501		(607	)		2,894
Other income (loss)		56		10	(a), (b), (c)		66		176		2	(a), (b), (c)		178
Income including noncontrolling interests before interest and income taxes		708		(302	)		406		3,677		(605	)		3,072
Interest and related charges		223		(47	) (a), (b), (k)		176		901		(34	) (a),(b), (k)		867
Income including noncontrolling interests before income taxes		485		(255	)		230		2,776		(571	)		2,205
Income taxes		145		(121	) (d)		24		1,004		(250	) (d)		754
Income from continuing operations including noncontrolling interests		340		(134	)		206		1,772		(321	)		1,451
Income (loss) from discontinued operations, net of tax		—		1	(b)		1		—		(25	) (b)		(25	)
Noncontrolling interests		6		—			6		18		—			18
Earnings	$	334	$	(133	)	$	201	$	1,754	$	(346	)	$	1,408
Earnings Per Share - Diluted	$	0.58	$	(0.23	)	$	0.35	$	3.05	$	(0.60	)	$	2.45
Average shares outstanding, diluted		571.2					571.2		574.6					574.6

Adjustments to Operating Earnings:

(a) Items related to Kewaunee nuclear merchant power station.

(b) Items related to Salem Harbor and State Line discontinued operations.

(c) Net gain/loss related our investment in nuclear decommissioning trust funds.

(d) Income tax effects for adjustments to operating results.

(e) Item related to Virginia deferred fuel.

(f) Benefit related to litigation with the Department of Energy for spent nuclear fuel-related costs at Millstone nuclear power station.

(g) PJM ancillary revenues adjustment related to prior year.

(h) Restoration costs associated with Hurricane Irene

(i) Earthquake related costs.

(j) Impairment charges related to excess emission allowances resulting from new EPA Air Pollution Rule.

(k) Items in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2009-2010 test years.

(l) Other miscellaneous items.

(m) Impairment charge related to certain electric utility generation assets.

¹⁾ Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

²⁾ Amounts have been recast to reflect the results of State Line and Salem Harbor generating stations as discontinued operations.

Note: Figures may not add due to rounding

February 28, 2013 32

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Reconciliation of 2012 Corporate and Other Operating Earnings to Reported Earnings

Corporate and Other

Unaudited Income Statements

(millions, except per share amounts)

	Three Months Ended December 31, 2012									Twelve Months Ended December 31, 2012
	Operating			Adjustments			GAAP			Operating			Adjustments			GAAP
Operating Revenue	$	148		$	117	(a), (f)	$	265		$	584		$	331	(a), (f)	$	915
Operating Expenses
Electric fuel and other energy-related purchases		—			32	(a), (f)		32			—			98	(a), (f)		98
Purchased electric capacity		—			—			—			—			—			—
Purchased gas		1			—			1			3			—			3
Other operations and maintenance		147			1,741	(a), (e), (f),  (g)		1,888			577			2,422	(a), (e), (f),  (g)		2,999
Depreciation, depletion and amortization		8			16	(a), (f)		24			30			38	(a), (f)		68
Other taxes		—			6	(a), (f)		6			21			20	(a), (f)		41
Total operating expenses		156			1,795			1,951			631			2,578			3,209
Income from operations		(8	)		(1,678	)		(1,686	)		(47	)		(2,247	)		(2,294	)
Other income (loss)		13			12	(a), (b), (f)		25			80			64	(a), (b), (f)		144
Income including noncontrolling interests before interest and income taxes		5			(1,666	)		(1,661	)		33			(2,183	)		(2,150	)
Interest and related charges		127			21	(a), (f)		148			496			50	(a), (f)		546
Income including noncontrolling interests before income taxes		(122	)		(1,687	)		(1,809	)		(463	)		(2,233	)		(2,696	)
Income taxes		(65	)		(628	) (c)		(693	)		(228	)		(808	) (c)		(1,036	)
Income from continuing operations including noncontrolling interests		(57	)		(1,059	)		(1,116	)		(235	)		(1,425	)		(1,660	)
Income (loss) from discontinued operations, net of tax		—			—			—			—			(22	) (d)		(22	)
Noncontrolling interests		—			—			—			—			—			—
Earnings (Loss) Contribution	$	(57	)	$	(1,059	)	$	(1,116	)	$	(235	)	$	(1,447	)	$	(1,682	)
Earnings Per Share	$	(0.10	)	$	(1.84	)	$	(1.94	)	$	(0.41	)	$	(2.52	)	$	(2.93	)
Average shares outstanding, diluted		575.0						575.0			573.9						573.9

Adjustments to Operating Earnings:

(a) Items related to Kewaunee nuclear merchant power station.

(b) Net gain/loss related to our investment in nuclear decommissioning trust funds.

(c) Income tax effects for items excluded from operating results.

(d) Items related to income/loss from State Line and Salem Harbor discontinued operations.

(e) Restoration costs associated with severe storms affecting our Dominion Virginia Power and Dominion North Carolina Power service territories.

(f) Items related to certain fossil fuel-fired merchant power stations, which Dominion decided to market for sale in the third quarter of 2012.

(g) Other miscellaneous items.

Note: Figures may not add due to rounding

February 28, 2013 33

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Reconciliation of 2011 Dominion Generation Earnings to Reported Earnings

Dominion Generation

Unaudited Summary of Operating results

(millions, except per share amounts)

	Three Months Ended December 31, 2011							Twelve Months Ended December 31, 2011
	Operating1		Adjustments			GAAP2		Operating1		Adjustments			GAAP2
Operating Revenue	$	1,634	$	(48	) (a)	$	1,586	$	7,670	$	(235	) (a)	$	7,435
Operating Expenses
Electric fuel and other energy-related purchases		731		(22	) (a)		709		3,210		(97	) (a)		3,113
Purchased electric capacity		100		—			100		408		—			408
Purchased gas		—		—			—		—		—			—
Other operations and maintenance		420		(25	) (a)		395		1,617		(77	) (a)		1,540
Depreciation, depletion and amortization		122		—			122		459		(2	) (a)		457
Other taxes		55		(1	) (a)		54		204		(5	) (a)		199
Total operating expenses		1,428		(48	)		1,380		5,898		(181	)		5,717
Income from operations		206		—			206		1,772		(54	)		1,718
Other income		24		(1	) (a)		23		61		(1	) (a)		60
Income including noncontrolling interests before interest and income taxes		230		(1	)		229		1,833		(55	)		1,778
Interest and related charges		56		(1	) (a)		55		219		(2	) (a)		217
Income including noncontrolling interests before income taxes		174		—			174		1,614		(53	)		1,561
Income taxes		53		1	(a)		54		601		(18	) (a)		583
Income including noncontrolling interests		121		(1	)		120		1,013		(35	)		978
Noncontrolling interests		4		—			4		10		—			10
Operating Earnings Contribution	$	117	$	(1	)	$	116	$	1,003	$	(35	)	$	968
Operating Earnings Per Share Contribution	$	0.20	$	—		$	0.20	$	1.74	$	(0.06	)	$	1.68
Average shares outstanding, diluted		571.2					571.2		574.6					574.6

Adjustments to Operating Earnings:

(a) Items related to Salem Harbor and State Line discontinued operations.

¹⁾ Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

²⁾ Amounts have been recast to reflect the results of State Line and Salem Harbor generating stations as discontinued operations.

Note: Figures may not add due to rounding

February 28, 2013 34

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Reconciliation of 2011 Corporate and Other Operating Earnings to Reported Earnings

Corporate and Other

Unaudited Income Statements

(millions, except per share amounts)

	Three Months Ended December 31, 2011									Twelve Months Ended December 31, 2011
	Operating			Adjustments			GAAP1			Operating			Adjustments			GAAP1
Operating Revenue	$	149		$	(39	) (a), (k), (m)	$	110		$	585		$	66	(a), (e), (g),  (k), (m)	$	651
Operating Expenses
Electric fuel and other energy-related purchases		—			9	(a)		9			—			42	(a), (e)		42
Purchased electric capacity		—			—			—			—			—			—
Purchased gas		1			19	(m)		20			5			19	(m)		24
Other operations and maintenance		149			243	(a), (h), (l),  (m)		392			578			550	(a), (f), (h),  (i), (j), (m)		1,128
Depreciation, depletion and amortization		7			1	(a)		8			28			—	(a), (f)		28
Other taxes		1			1	(a)		2			22			8	(a)		30
Total operating expenses		158			273			431			633			619			1,252
Income from operations		(9	)		(312	)		(321	)		(48	)		(553	)		(601	)
Other income (loss)		25			11	(a), (b)		36			85			3	(a), (b)		88
Income including noncontrolling interests before interest and income taxes		16			(301	)		(285	)		37			(550	)		(513	)
Interest and related charges		137			(46	) (a), (k)		91			546			(32	) (a), (k)		514
Income including noncontrolling interests before income taxes		(121	)		(255	)		(376	)		(509	)		(518	)		(1,027	)
Income taxes		(73	)		(122	) (d)		(195	)		(238	)		(232	) (c)		(470	)
Income from continuing operations including noncontrolling interests		(48	)		(133	)		(181	)		(271	)		(286	)		(557	)
Income (loss) from discontinued operations, net of tax		—			1	(d)		1			—			(25	) (d)		(25	)
Noncontrolling interests		—			—			—			—			—			—
Earnings (Loss) Contribution	$	(48	)	$	(132	)	$	(180	)	$	(271	)	$	(311	)	$	(582	)
Earnings Per Share	$	(0.09	)	$	(0.23	)	$	(0.32	)	$	(0.47	)	$	(0.54	)	$	(1.01	)
Average shares outstanding, diluted		571.2						571.2			574.6						574.6

Adjustments to Operating Earnings:

(a) Items related to Kewaunee nuclear merchant power station.

(b) Net gain/loss related our investment in nuclear decommissioning trust funds.

(c) Income tax effects for adjustments to operating results.

(d) Items related to Salem Harbor and State Line discontinued operations.

(e) Item related to Virginia deferred fuel.

(f) Benefit related to litigation with the Department of Energy for spent nuclear fuel-related costs at Millstone nuclear power station.

(g) PJM ancillary revenues adjustment related to prior year.

(h) Restoration costs associated with Hurricane Irene

(i) Earthquake related costs.

(j) Impairment charges related to excess emission allowances resulting from new EPA Air Pollution Rule.

(k) Items in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2009-2010 test years.

(l) Impairment charge related to certain electric utility generation assets.

(m) Other miscellaneous items.

¹⁾ Amounts have been recast to reflect the results of State Line and Salem Harbor generating stations as discontinued operations.

Note: Figures may not add due to rounding

February 28, 2013 35

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Reconciliation of 2012 Operating Earnings to Reported Earnings

Dominion

Reconciliation of 2012 Operating to 2012 GAAP

Unaudited, Operating Segments

(millions, except per share amounts)

Description	2012 Operating			Adjustments			2012 GAAP
Dominion Virginia Power EBIT	$	1,105					$	1,105
Dominion Energy EBIT		950						950
Dominion Generation EBIT		1,580						1,580
Corporate and Other & Eliminations EBIT		(73	)		(2,183	) (a), (b), (e), (f), (g)		(2,256	)
Total EBIT	$	3,562		($	2,183	)	$	1,379
Consolidated Interest		832			50	(a), (f)		882
Consolidated Income Taxes		954			(808	) (c)		146
Noncontrolling Interests		27						27
Income(loss) from Discontinued Operations		0			(22	) (d)		(22	)
Earnings	$	1,749		($	1,447	)	$	302
Average Diluted Shares Outstanding		573.9			573.9			573.9
Operating EPS	$	3.05			—			—
Adjustments		—		($	2.52	)		—
Reported EPS		—			—		$	0.53
Note: Totals may not add due to rounding

Adjustments to Operating Earnings:

(a) Items related to Kewaunee nuclear merchant power station.

(b) Net gain/loss of our investment in nuclear decommissioning trust funds.

(c) Income tax effects for items excluded from operating results.

(d) Items related to State Line and Salem Harbor discontinued operations.

(e) Restoration costs associated with severe storms affecting our Dominion Virginia Power and Dominion North Carolina Power service territories.

(f) Items related to certain fossil fuel-fired merchant power stations, which Dominion decided to market for sale in the third quarter of 2012.

(g) Other miscellaneous items.

February 28, 2013 36

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Reconciliation of 2011 Operating Earnings to Reported Earnings

Reconciliation of 2011 Operating to 2011 GAAP

Unaudited, Operating Segments

(millions, except per share amounts)

Description	2011 Operating1			Adjustments			2011 GAAP2
Dominion Virginia Power EBIT	$	1,012					$	1,012
Dominion Energy EBIT		901						901
Dominion Generation EBIT		1,833			(55	) (a)		1,778
Corporate and Other & Eliminations EBIT		(69	)		(550	) (b), (c), (e), (f), (f), (g), (h), (i), (j), (k)		(619	)
Total EBIT	$	3,677		($	605	)	$	3,072
Consolidated Interest		901			(34	) (a),(b), (h)		867
Consolidated Income Taxes		1,004			(250	) (d)		754
Noncontrolling Interests		18						18
Income(loss) from Discontinued Operations		0			(25	) (a)		(25	)
Earnings	$	1,754		($	346	)	$	1,408
		574.6			574.6			574.6
Operating EPS	$	3.05			—			—
Adjustments		—		($	0.60	)		—
Reported EPS		—			—		$	2.45
Note: Totals may not add due to rounding

Adjustments to Operating Earnings:

(a) Items related to State Line and Salem Harbor discontinued operations.

(b) Items related to Kewaunee nuclear merchant power station.

(c) Net gain/loss related to our investment in nuclear decommissioning trust funds.

(d) Income tax effects for adjustments to operating results.

(e) Impairment charges related to certain electric utility generation assets.

(f) Restoration costs associated with Hurricane Irene.

(g) Impairment charges related to excess emission allowances resulting from new EPA Air Pollution Rule.

(h) Items in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2009-2010 test years.

(i) Earthquake related costs.

(j) Benefit related to litigation with the Department of Energy for spent nuclear fuel-related costs at Millstone nuclear power station.

(k) Other miscellaneous items.

¹⁾ Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

²⁾ Amounts have been recast to reflect the results of State Line and Salem Harbor generating stations as discontinued operations.

February 28, 2013 37

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Reconciliation of 1Q12 and 4Q12 Operating Earnings to Reported Earnings

Reconciliation of 4Q12 Operating to 4Q12 GAAP

Unaudited, Operating Segments

(millions, except per share amounts)

Description	4Q12 Operating			Adjustments			4Q12 GAAP
Dominion Virginia Power EBIT	$	257					$	257
Dominion Energy EBIT		330						330
Dominion Generation EBIT		257						257
Corporate and Other & Eliminations EBIT		(21	)		(1,666	) (a), (b), (d), (e), (f)		(1,687	)
Total EBIT	$	823		($	1,666	)	($	843	)
Consolidated Interest		194			21	(a), (f)		215
Consolidated Income Taxes		222			(628	) (c)		(406	)
Noncontrolling Interests		7						7
Income(loss) from Discontinued Operations		0			0			0
Earnings	$	400		($	1,059	)	($	659	)
Average Diluted Shares Outstanding		575.0			575.0			575.0
Operating EPS	$	0.69			—			—
Adjustments		—		($	1.84	)		—
Reported EPS		—			—		($	1.15	)

Reconciliation of 1Q12 Operating to 1Q12 GAAP¹

Unaudited, Operating Segments

(millions, except per share amounts)

Description	1Q12 Operating			Adjustments			1Q12 GAAP
Dominion Virginia Power EBIT	$	324					$	324
Dominion Energy EBIT		256						256
Dominion Generation EBIT		394						394
Corporate and Other & Eliminations EBIT		(3	)		16	(a), (b)		13
Total EBIT	$	971		$	16		$	987
Consolidated Interest		223			5	(a)		228
Consolidated Income Taxes		255			4	(c)		259
Noncontrolling Interests		7						7
Income(loss) from Discontinued Operations		0			1	(g)		1
Earnings	$	486		$	8		$	494
Average Diluted Shares Outstanding		571.9			571.9			571.9
Operating EPS	$	0.85			—			—
Adjustments		—		$	0.01			—
Reported EPS		—			—		$	0.86

Note: Totals may not add due to rounding

Adjustments to Operating Earnings:

(a) Items related to Kewaunee nuclear merchant power station.

(b) Net gain/loss of our investment in nuclear decommissioning trust funds.

(c) Income tax effects for items excluded from operating results.

(d) Restoration costs associated with severe storms affecting our Dominion Virginia Power and Dominion North Carolina Power service territories.

(e) Items related to certain fossil fuel-fired merchant power stations, which Dominion decided to market for sale in the third quarter of 2012.

(f) Other miscellaneous items.

(g) Items related to State Line and Salem Harbor discontinued operations.

February 28, 2013 38

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

Reconciliation of 4Q11 Operating Earnings to Reported Earnings

Reconciliation of 4Q11 Operating to 4Q11 GAAP

Unaudited, Operating Segments

(millions, except per share amounts)

Description	4Q11 Operating1			Adjustments			4Q11 GAAP2
Dominion Virginia Power EBIT	$	232					$	232
Dominion Energy EBIT		258						258
Dominion Generation EBIT		230			(1	) (a)		229
Corporate and Other & Eliminations EBIT		(12	)		(301	) (b), (c), (e), (f), (g), (h)		(313	)
Total EBIT	$	708		($	302	)	$	406
Consolidated Interest		223			(47	) (a), (b), (f)		176
Consolidated Income Taxes		145			(121	) (d)		24
Noncontrolling Interests		6						6
Income(loss) from Discontinued Operations		0			1	(a)		1
Earnings	$	334		($	133	)	$	201
		571.2			571.2			571.2
Operating EPS	$	0.58			—			—
Adjustments		—		($	0.23	)		—
Reported EPS		—			—		$	0.35

Note: Totals may not add due to rounding

Adjustments to Operating Earnings:

(a) Items related to State Line and Salem Harbor discontinued operations.

(b) Items related to Kewaunee nuclear merchant power station.

(c) Net gain/loss related to our investment in nuclear decommissioning trust funds.

(d) Income tax effects for adjustments to operating results.

(e) Adjustment to exclude an impairment charge related to certain electric utility generation assets.

(f) Adjustment to exclude items in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2009-2010 test years.

(g) Adjustment to exclude impact of restoration costs associated with Hurricane Irene.

(h) Adjustment to exclude other miscellaneous items.

¹⁾ Reflects amounts as originally reported prior to recast of results for State Line and Salem Harbor generating stations as discontinued operations.

²⁾ Amounts have been recast to reflect the results of State Line and Salem Harbor generating stations as discontinued operations.

February 28, 2013 39

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

2013 Earnings Expectations

Earnings Per Share (diluted)

Reconciliation of measures prepared in accordance with Generally Accepted Accounting Principles (GAAP) versus non-GAAP measures

1Q 2013 Operating Earnings (estimate):	$	0.80 - $0.95
FY 2013 Operating Earnings (estimate):	$	3.20 - $3.50
1Q 2013 Reported Earnings (estimate):		See Note 1 below
FY 2013 Reported Earnings (estimate):		See Note 1 below

1. In providing its first-quarter and full-year 2013 operating earnings guidance the company notes that there could be differences between expected reported earnings and estimated operating earnings for matters such as, but not limited to, divestitures or changes in accounting principles. At this time, Dominion management is not able to estimate the aggregate impact, if any, of these items on reported earnings. Accordingly, Dominion is not able to provide a corresponding GAAP equivalent for its operating earnings guidance.

Dominion uses operating earnings as the primary performance measurement of its earnings guidance and results for public communications with analysts and investors. Dominion also uses operating earnings internally for budgeting, for reporting to the board of directors, for the company’s incentive compensation plans and for its targeted dividend payouts and other purposes. Dominion management believes operating earnings provide a more meaningful representation of the company’s fundamental earnings power.

Dominion’s estimates of first-quarter and full-year 2013 earnings are subject to various risks and uncertainties. Factors that could cause actual results to differ materially from management’s projections, forecasts, estimates and expectations may include factors that are beyond the company’s ability to control or estimate precisely, including fluctuations in energy-related commodity prices, estimates of future market conditions, additional competition in the electric industry, changes in the demand for Dominion’s services, access to and costs of capital, fluctuations in the value of our pension assets and assets held in our decommissioning trusts, asset portfolio reviews and resulting decisions to acquire, divest or retire assets, the receipt of regulatory approvals for, and timing of, planned projects, acquisitions and divestitures, and the ability to complete planned construction or expansion projects within the terms and timeframes initially anticipated. Other factors include, but are not limited to, weather conditions and other events, including the effects of hurricanes, earthquakes, high winds, major storms and changes in water temperatures on operations, the risk associated with the operation of nuclear facilities, unplanned outages of Dominion’s generation facilities, state and federal legislative and regulatory developments and changes to environmental and other laws and regulations, including those related to climate change, greenhouse gases and other emissions to which we are subject, political and economic conditions, industrial, commercial and residential growth or decline in Dominion’s service area, risks of operating businesses in regulated industries that are subject to changing regulatory structures, changes to regulated gas and electric rates collected by Dominion, changes to rating agency requirements and ratings, changing financial accounting standards, fluctuations in interest rates, changes in federal and state tax laws, employee workforce factors, including collective bargaining, counter-party credit and performance risks, adverse outcomes in litigation matters or regulatory proceedings, the risk of hostile cyber intrusions and other uncertainties. Other risk factors are detailed from time to time in Dominion’s most recent quarterly report on Form 10-Q or annual report on Form 10-K filed with the Securities and Exchange Commission.

February 28, 2013 40

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

DOMINION – REVISED 4Q12 EARNINGS RELEASE KIT

APPENDIX

List of Revised Schedules

Schedule	Page Number
Schedule 1 - Segment Operating Earnings		8
Schedule 2 - Reconciliation of 2012 Operating Earnings to Reported Earnings		9
Schedule 4 - Reconciliation of 2012 Earnings to 2011		11
Consolidated Financial Statements (GAAP) - Dominion Consolidated
Preliminary & Unaudited Income Statements (GAAP Based)		12
Preliminary & Unaudited Balance Sheets (Summarized)		13
Preliminary & Unaudited Statements of Cash Flows (Summarized)		14
Segment Operating Earnings Results
Dominion Consolidated - Unaudited Summary of Operating Results		15
Corporate and Other - Unaudited Summary of Operating Results		19
Schedule of Changes in Capitalization - Dominion Resources, Inc. & Subsidiaries		28
Reconciliation of Operating to Reported Earnings
Reconciliation of 2012 Consolidated Operating Earnings to Reported Earnings		32
Reconciliation of 2012 Corporate and Other Operating Earnings to Reported Earnings		34
Reconciliation of 2012 Operating Earnings to Reported Earnings		37
Reconciliation of 4Q12 Operating Earnings to Reported Earnings		39

February 28, 2013 41

Please refer to page 3 for risks and uncertainties related to projections and forward-looking statements.

EX-99.2

Exhibit 99.2

Dominion

Unaudited Supplemental Summary of 2012 Operating Earnings

(millions, except per share amounts)

	12 Months Ended 12/31/12			Quarter ended 12/31/12			Quarter ended 09/30/12			Quarter ended 06/30/12			Quarter Ended 03/31/12
Dominion Virginia Power
Electric Distribution
Operating revenue	$	1,274		$	310		$	345		$	309		$	310
Expenses:
Commodity purchases		2			1			0			1			0
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		331			79			93			82			77
Depreciation, depletion and amortization		315			80			80			78			77
Other		57			11			8			21			17
Earnings including noncontrolling interests before interest and taxes	$	569		$	139		$	164		$	127		$	139
Electric Transmission
Operating revenue	$	638		$	143		$	176		$	154		$	165
Expenses:
Commodity purchases		0			0			0			0			0
Purchased electric capacity		16			0			0			7			9
Other operations and maintenance		199			36			71			44			48
Depreciation, depletion and amortization		77			20			19			19			19
Other		3			0			0			1			2
Earnings including noncontrolling interests before interest and taxes	$	343		$	87		$	86		$	83		$	87
Dominion Retail
Operating revenue	$	1,642		$	406		$	336		$	369		$	531
Expenses:
Commodity purchases		1,319			343			309			264			403
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		102			24			28			26			24
Depreciation, depletion and amortization		10			2			2			3			3
Other		17			5			5			4			3
Earnings including noncontrolling interests before interest and taxes	$	194		$	32		($	8	)	$	72		$	98
Segment Eliminations
Operating revenue	($	57	)	($	16	)	($	15	)	($	13	)	($	13	)
Expenses:
Commodity purchases		0			0			0			0			0
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		(57	)		(16	)		(15	)		(13	)		(13	)
Depreciation, depletion and amortization		0			0			0			0			0
Other		0			0			0			0			0
Earnings including noncontrolling interests before interest and taxes	$	0		$	0		$	0		$	0		$	0
Dominion Virginia Power Total
Operating revenue	$	3,497		$	843		$	842		$	819		$	993
Expenses:
Commodity purchases		1,321			344			309			265			403
Purchased electric capacity		16			0			0			7			9
Other operations and maintenance		576			124			177			139			136
Depreciation, depletion and amortization		402			102			101			100			99
Other		77			16			13			26			22
Earnings including noncontrolling interests before interest and taxes	$	1,105		$	257		$	242		$	282		$	324
Interest and related charges		187			42			46			48			51
Income taxes		351			82			75			89			105
Noncontrolling interests		8			2			2			2			2
Operating earnings contribution	$	559		$	131		$	119		$	143		$	166
Average shares outstanding, diluted		573.9			575.0			574.7			573.1			571.9
Operating earnings per share contribution		0.98			0.23			0.21			0.25			0.29

Notes:

• Commodity purchases = Electric fuel and other energy-related purchases + Purchased gas

• Other = Other Taxes - Other Income

• Operating segment contribution to operating earnings equals contribution to GAAP earnings

• Figures may not add due to rounding

Page 1 of 5

Dominion

Unaudited Supplemental Summary of 2012 Operating Earnings

(millions, except per share amounts)

	12 Months Ended 12/31/12			Quarter ended 12/31/12			Quarter ended 09/30/12			Quarter ended 06/30/12			Quarter Ended 03/31/12
Dominion Energy
Gas Distribution (DEO & HGI)
Operating revenue	$	848		$	251		$	137		$	162		$	298
Expenses:
Commodity purchases		183			71			12			21			79
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		299			79			57			61			102
Depreciation, depletion and amortization		73			16			21			18			18
Other		104			30			16			22			36
Earnings including noncontrolling interests before interest and taxes	$	189		$	55		$	31		$	40		$	63
Gas Transmission
Operating revenue	$	1,263		$	353		$	287		$	303		$	320
Expenses:
Commodity purchases		219			60			48			68			43
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		188			4			67			55			62
Depreciation, depletion and amortization		142			39			35			34			34
Other		29			7			9			8			5
Earnings including noncontrolling interests before interest and taxes	$	685		$	243		$	128		$	138		$	176
Producer Services
Operating revenue	$	733		$	191		$	170		$	147		$	225
Expenses:
Commodity purchases		659			160			152			139			208
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		23			5			8			5			5
Depreciation, depletion and amortization		1			0			0			1			0
Other		(26	)		(6	)		(8	)		(7	)		(5	)
Earnings including noncontrolling interests before interest and taxes	$	76		$	32		$	18		$	9		$	17
Segment Eliminations
Operating revenue	($	101	)	($	31	)	($	22	)	($	21	)	($	27	)
Expenses:
Commodity purchases		(92	)		(28	)		(20	)		(19	)		(25	)
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		(9	)		(3	)		(2	)		(2	)		(2	)
Depreciation, depletion and amortization		0			0			0			0			0
Other		0			0			0			0			0
Earnings including noncontrolling interests before interest and taxes	$	0		$	0		$	0		$	0		$	0
Dominion Energy Total
Operating revenue	$	2,743		$	764		$	572		$	591		$	816
Expenses:
Commodity purchases		969			263			192			209			305
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		501			85			130			119			167
Depreciation, depletion and amortization		216			55			56			53			52
Other		107			31			16			24			36
Earnings including noncontrolling interests before interest and taxes	$	950		$	330		$	178		$	186		$	256
Interest and related charges		47			12			11			11			13
Income taxes		352			129			63			66			94
Noncontrolling interests		0			0			0			0			0
Operating earnings contribution	$	551		$	189		$	104		$	109		$	149
Average shares outstanding, diluted		573.9			575.0			574.7			573.1			571.9
Operating earnings per share contribution		0.96			0.33			0.18			0.19			0.26

Notes:

• Commodity purchases = Electric fuel and other energy-related purchases + Purchased gas

• Other = Other Taxes - Other Income

• Operating segment contribution to operating earnings equals contribution to GAAP earnings

• Figures may not add due to rounding

Page 2 of 5

Dominion

Unaudited Supplemental Summary of 2012 Operating Earnings

(millions, except per share amounts)

	12 Months Ended 12/31/12		Quarter ended 12/31/12		Quarter ended 09/30/12		Quarter ended 06/30/12		Quarter Ended 03/31/12
Dominion Generation
Utility Generation
Operating revenue	$	5,379	$	1,196	$	1,581	$	1,307	$	1,295
Expenses:
Commodity purchases		2,362		513		634		602		613
Purchased electric capacity		370		89		86		91		104
Other operations and maintenance		921		242		227		256		196
Depreciation, depletion and amortization		390		103		104		91		92
Other		81		13		17		26		25
Earnings including noncontrolling interests before interest and taxes	$	1,255	$	236	$	513	$	241	$	265
Merchant Generation
Operating revenue	$	1,471	$	309	$	350	$	386	$	426
Expenses:
Commodity purchases		478		118		109		123		128
Purchased electric capacity		1		1		0		0		0
Other operations and maintenance		477		133		94		137		113
Other		80		16		23		20		21
Earnings before interest, taxes and DD&A	$	435	$	41	$	124	$	106	$	164
Depreciation, depletion and amortization		110		20		20		35		35
Earnings including noncontrolling interests before interest and taxes	$	325	$	21	$	104	$	71	$	129
Dominion Generation Total
Operating revenue	$	6,850	$	1,505	$	1,931	$	1,693	$	1,721
Expenses:
Commodity purchases		2,840		631		743		725		741
Purchased electric capacity		371		90		86		91		104
Other operations and maintenance		1,398		375		321		393		309
Depreciation, depletion and amortization		500		123		124		126		127
Other		161		29		40		46		46
Earnings including noncontrolling interests before interest and taxes	$	1,580	$	257	$	617	$	312	$	394
Interest and related charges		208		39		46		63		60
Income taxes		479		76		204		92		107
Noncontrolling interests		19		5		4		5		5
Operating earnings contribution	$	874	$	137	$	363	$	152	$	222
Average shares outstanding, diluted		573.9		575.0		574.7		573.1		571.9
Operating earnings per share contribution		1.52		0.23		0.63		0.27		0.39

Notes:

• Commodity purchases = Electric fuel and other energy-related purchases + Purchased gas

• Other = Other Taxes - Other Income

• Operating segment contribution to operating earnings equals contribution to GAAP earnings

• Figures may not add due to rounding

Page 3 of 5

Dominion

Unaudited Supplemental Summary of 2012 Operating Earnings

(millions, except per share amounts)

	12  Months Ended 12/31/12			Quarter ended 12/31/12			Quarter ended 09/30/12			Quarter ended 06/30/12			Quarter Ended 03/31/12
THIS SCHEDULE PRESENTS MEASURES OF OPERATING EARNINGS THAT EXCLUDE CERTAIN ITEMS THAT ARE INCLUDED IN GAAP. PLEASE REFER TO THE FOLLOWING PAGE FOR THE GAAP EQUIVALENT OF THIS SCHEDULE.
Corporate and Other
Operating revenue	$	584		$	148		$	156		$	137		$	143
Expenses:
Commodity purchases		3			1			1			0			1
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		577			147			156			142			132
Depreciation, depletion and amortization		30			8			7			8			7
Other		(59	)		(13	)		(13	)		(13	)		(20	)
Earnings including noncontrolling interests before interest and taxes		33			5			5			0			23
Interest and related charges		496			127			119			125			125
Income taxes		(228	)		(65	)		(54	)		(58	)		(51	)
Noncontrolling interests		0			0			0			0			0
Operating earnings contribution	($	235	)	($	57	)	($	60	)	($	67	)	($	51	)
Average shares outstanding, diluted		573.9			575.0			574.7			573.1			571.9
Operating earnings per share contribution		(0.41	)	($	0.10	)		(0.10	)	($	0.12	)		(0.09	)
Total Segment Eliminations and Adjustments
Operating revenue	($	912	)	($	210	)	($	217	)	($	229	)	($	256	)
Expenses:
Commodity purchases		(306	)		(57	)		(54	)		(83	)		(112	)
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		(606	)		(153	)		(163	)		(146	)		(144	)
Depreciation, depletion and amortization		0			0			0			0			0
Other		106			26			27			27			26
Earnings including noncontrolling interests before interest and taxes		(106	)		(26	)		(27	)		(27	)		(26	)
Interest and related charges		(106	)		(26	)		(27	)		(27	)		(26	)
Income taxes		0			0			0			0			0
Noncontrolling interests		0			0			0			0			0
Operating earnings contribution	$	0		$	0		$	0		$	0		$	0
Average shares outstanding, diluted		573.9			575.0			574.7			573.1			571.9
Operating earnings per share contribution	$	0.00		$	0.00		$	0.00		$	0.00		$	0.00
Dominion Total
Operating revenue	$	12,762		$	3,050		$	3,284		$	3,011		$	3,417
Expenses:
Commodity purchases		4,827			1,182			1,191			1,116			1,338
Purchased electric capacity		387			90			86			98			113
Other operations and maintenance		2,446			578			621			647			600
Depreciation, depletion and amortization		1,148			288			288			287			285
Other		392			89			83			110			110
Earnings including noncontrolling interests before interest and taxes	$	3,562		$	823		$	1,015		$	753		$	971
Interest and related charges		832			194			195			220			223
Income taxes		954			222			288			189			255
Noncontrolling interests		27			7			6			7			7
Consolidated operating earnings attributable to Dominion	$	1,749		$	400		$	526		$	337		$	486
Average shares outstanding, diluted		573.9			575.0			574.7			573.1			571.9
Consolidated operating earnings per share		3.05			0.69			0.92			0.59			0.85

Notes:

• Commodity purchases = Electric fuel and other energy-related purchases + Purchased gas

• Other = Other Taxes - Other Income

• Figures may not add due to rounding

Page 4 of 5

Dominion

Unaudited Supplemental Summary of 2012 GAAP Earnings

(millions, except per share amounts)

	12 Months Ended 12/31/12			Quarter ended 12/31/12			Quarter ended 09/30/12			Quarter ended 06/30/12			Quarter Ended 03/31/12
THIS SCHEDULE PRESENTS GAAP MEASURES OF REPORTED NET INCOME ATTRIBUTABLE TO DOMINION. PLEASE REFER TO THE PRECEDING PAGE FOR THE OPERATING EARNINGS EQUIVALENT OF THIS SCHEDULE.
Corporate and Other
Operating revenue	$	915		$	265		$	283		$	179		$	188
Expenses:
Commodity purchases		101			33			53			5			10
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		2,999			1,888			669			277			165
Depreciation, depletion and amortization		68			24			25			10			9
Other		(103	)		(19	)		(28	)		(21	)		(35	)
Income including noncontrolling interests before interest and taxes		(2,150	)		(1,661	)		(436	)		(92	)		39
Interest and related charges		546			148			139			129			130
Income taxes		(1,036	)		(693	)		(203	)		(93	)		(47	)
Income from continuing operations including noncontrolling interests		(1,660	)		(1,116	)		(372	)		(128	)		(44	)
Income(loss) from discontinued operations, net of tax		(22	)		0			(5	)		(18	)		1
Noncontrolling interests		0			0			0			0			0
Reported Earnings (Loss) Contribution	($	1,682	)		(1,116	)	($	377	)	($	146	)	($	43	)
Average shares outstanding, diluted		573.9			575.0			574.7			573.1			571.9
Reported Earnings (Loss) Per Share Contribution		(2.93	)		(1.94	)		(0.66	)		(0.26	)		(0.08	)
Total Segment Eliminations and Adjustments
Operating revenue	($	912	)	($	210	)	($	217	)	($	229	)	($	256	)
Expenses:
Commodity purchases		(306	)		(57	)		(54	)		(83	)		(112	)
Purchased electric capacity		0			0			0			0			0
Other operations and maintenance		(606	)		(153	)		(163	)		(146	)		(144	)
Depreciation, depletion and amortization		0			0			0			0			0
Other		106			26			27			27			26
Income including noncontrolling interests before interest and taxes		(106	)		(26	)		(27	)		(27	)		(26	)
Interest and related charges		(106	)		(26	)		(27	)		(27	)		(26	)
Income taxes		0			0			0			0			0
Noncontrolling interests		0			0			0			0			0
Segment Eliminations Earnings (Loss) Contribution	$	0		$	0		$	0		$	0		$	0
Average shares outstanding, diluted		573.9			575.0			574.7			573.1			571.9
Segment Eliminations Earnings (Loss) Per Share Contribution	$	0.00		$	0.00		$	0.00		$	0.00		$	0.00
Dominion Total
Operating revenue	$	13,093		$	3,167		$	3,411		$	3,053		$	3,462
Expenses:
Commodity purchases		4,925			1,214			1,243			1,121			1,347
Purchased electric capacity		387			90			86			98			113
Other operations and maintenance		4,868			2,319			1,134			782			633
Depreciation, depletion and amortization		1,186			304			306			289			287
Other taxes		571			132			124			146			169
Total operating expenses		11,937			4,059			2,893			2,436			2,549
Income from Operations		1,156			(892	)		518			617			913
Other income (loss)		223			49			56			44			74
Income including noncontrolling interests before interest and taxes		1,379			(843	)		574			661			987
Interest and related charges		882			215			215			224			228
Income before taxes		497			(1,058	)		359			437			759
Income taxes		146			(406	)		139			154			259
Income from continuing operations including noncontrolling interests		351			(652	)		220			283			500
Income(loss) from discontinued operations, net of tax		(22	)		0			(5	)		(18	)		1
Noncontrolling interests		27			7			6			7			7
Net Income attributable to Dominion	$	302		($	659	)	$	209		$	258		$	494
Average shares outstanding, diluted		573.9			575.0			574.7			573.1			571.9
Consolidated reported earnings per share		0.53			(1.15	)		0.36			0.45			0.86

Notes:

• Commodity purchases = Electric fuel and other energy-related purchases + Purchased gas

• Other = Other Taxes - Other Income

• Figures may not add due to rounding

Page 5 of 5

EX-99.3

Exhibit 99.3

Towers Watson Energy Services Executive Survey participants:

Acciona	Entergy	Pacific Gas & Electric
AGL Resources	EQT Corporation	Pepco Holding
Allete	ERCOT	Pinnacle West Capital
Alliant Energy	Exelon	PJM Interconnection
Ameren	FirstEnergy	PNM Resources
American Electric Power	First Solar	Portland General Electric
Areva	GenOn Energy	PPL
ATC Management	Hawaiian Electric	Progress Energy
Avista	Iberdrola Renewables	Proliance Holdings
BG US Services	IDACORP	Public Service Enterprise Group
Black Hills Power and Light	Integrys Energy Group	Puget Energy
California Independent System	IPR – GDF SUEZ North America	Regency Energy Partners LP
Calpine	ISO New England	Salt River Project
CenterPoint Energy	Kinder Morgan	Santee Cooper
CH Energy Group	LES	SCANA
Cleco	LG&E and KU Energy Services	SemGroup
CMS Energy	Lower Colorado River Authority	Sempra Energy
Colorado Springs Utilities	McDermott	Southern Company Services
Consolidated Edison	MDU Resources	Southern Union Company
Constellation Energy	MGE Energy	Southwest Power Pool
Covanta Holdings	MidAmerican Holdings	Spectra Energy
	Midwest Independent Transmission	STP Nuclear Operating
CPS Energy	New York Independent System Operator	System Operator
Crosstex Energy	New York Power Authority	TECO Energy
DCP Midstream	NextEra Energy	Tennessee Valley Authority
Dominion Resources	Nicor	Trans Bay Cable
DPL	Northeast Utilities	TransCanada
DTE Energy	NorthWestern Energy	UIL Holdings
Duke Energy	NRG Energy	UniSource Energy
Edison International	NSTAR	Unitil
EDP Renewables North America LLC	Nuscale Power	Vectren
El Paso Corporation	NV Energy	Westar Energy
El Paso Electric	NW Natural	Westinghouse Electric
Enbridge Energy	OGE Energy	Williams Companies
Energen	Oglethorpe Power	Wisconsin Energy
Energy Future Holdings	Omaha Public Power	Wolf Creek Nuclear
Energy Northwest	Operator	Xcel

XML

Dispositions (Tables)

12 Months Ended

Dec. 31, 2012

State Line and Salem Harbor

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement Disclosures

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

Year Ended December 31,	2012			2011			2010
(millions)
Operating revenue	$	57		$	233		$	269
Loss before income taxes(1)	(49		)	(34		)	(158		)

(1) Includes long-lived asset impairment charges of $55 million and $194 million in 2011 and 2010, respectively.

Peoples

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement Disclosures

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:

Year Ended December 31,	2010
(millions)
Operating revenue	$	67
Loss before income taxes	(134		)	(1)

(1) Includes a loss and other charges related to the sale of Peoples.

XML

Employee Benefit Plans (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended
	Jan. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual return on plan assets			$ 743,000,000	$ 273,000,000
Expected return on pension and other postretirement plan assets			509,000,000	519,000,000
Previous eligible age for post retirement benefits with 10 years of service			55 years
New eligible age for postretirement benefits with 10 Years of service			58 years
Other postretirement benefit plan obligation reduction	71,000,000
Federal subsidy received			5,000,000
Decrease in other postretirement benefit obligations due to federal subsidy			170,000,000
Accumulated benefit obligation			5,500,000,000	4,500,000,000
Cumulative required contribution period (years)			10 years
Expected contribution to voluntary employees beneficiary association		14,000,000
Employer contributions			40,000,000	38,000,000	39,000,000
U.S. equity:
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined benefit plan, actual plan asset allocations			28.00%
Non-U.S. equity:
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined benefit plan, actual plan asset allocations			18.00%
Fixed Income
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined benefit plan, actual plan asset allocations			33.00%
Real estate:
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined benefit plan, actual plan asset allocations			3.00%
Other alternative investments
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined benefit plan, actual plan asset allocations			18.00%
Virginia Electric and Power Company
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net periodic benefit (credit) cost			72,000,000	50,000,000	84,000,000
Employer contributions			15,000,000	14,000,000	14,000,000
Virginia Electric and Power Company | Dominion Retiree Health And Welfare Plan
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net periodic benefit (credit) cost			$ 13,000,000	$ 23,000,000	$ 59,000,000

XML

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

General Discussion of Pension and Other Postretirement Benefits [Abstract]

Pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans funded status

The following table summarizes the changes in Dominion's pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans' funded status:

	Pension Benefits						Other Postretirement Benefits
Year Ended December 31,	2012			2011			2012			2011
(millions, except percentages)
Changes in benefit obligation:
Benefit obligation at beginning of year	$	4,981		$	4,490		$	1,493		$	1,707
Service cost	116			108			44			48
Interest cost	268			258			79			94
Benefits paid	(208		)	(215		)	(88		)	(83		)
Actuarial (gains) losses during the year	967			340			191			(210		)
Plan amendments	1			—			1			(70		)
Settlements and curtailments(2)	—			—			(6		)	(1		)
Medicare Part D reimbursement	—			—			5			5
Early Retirement Reimbursement Program	—			—			—			3
Benefit obligation at end of year	$	6,125		$	4,981		$	1,719		$	1,493
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	5,145		$	5,106		$	1,042		$	1,031
Actual return on plan assets	611			247			132			26
Employer contributions	5			7			16			19
Benefits paid	(208		)	(215		)	(34		)	(34		)
Fair value of plan assets at end of year	$	5,553		$	5,145		$	1,156		$	1,042
Funded status at end of year	$	(572	)	$	164		$	(563	)	$	(451	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	701			677			1			4
Other current liabilities	(2		)	(3		)	(4		)	(3		)
Noncurrent pension and other postretirement benefit liabilities	(1,271		)	(510		)	(560		)	(452		)
Net amount recognized	$	(572	)	$	164		$	(563	)	$	(451	)
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate	4.4		%	5.5		%	4.4		%	5.5		%
Weighted average rate of increase for compensation	4.21		%	4.21		%	4.22		%	4.22		%

Benefit obligation in excess of plan asset

The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets:

	Pension Benefits				Other Postretirement Benefits
As of December 31,	2012		2011		2012		2011
(millions)
Benefit obligation	$	5,462	$	4,416	$	1,591	$	1,375
Fair value of plan assets	4,189		3,903		1,027		920

Accumulated benefit obligation in excess of plan assets

The following table provides information on the ABO and fair value of plan assets for pension plans with an ABO in excess of plan assets:

As of December 31,	2012(1)		2011
(millions)
Accumulated benefit obligation	$	4,850	$	95
Fair value of plan assets	4,189		—

(1) The increase from 2011 is primarily due to a decrease in the discount rate.

Benefit payments expected future service

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Estimated Future Benefit Payments
	Pension Benefits		Other  Postretirement Benefits
(millions)
2013	$	231	$	89
2014	245		93
2015	255		96
2016	300		100
2017	334		103
2018-2022	1,749		555

Fair values of pension and post retirement plan assets by asset category

The fair values of Dominion's pension plan assets by asset category are as follows:

	Fair Value Measurements
	Pension Plans
At December 31,	2012								2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	—	$	195	—		$	195	1		$	84	—		$	85
U.S. equity:
Large Cap	927		104		—		1,031		805		123		—		928
Other	425		99		—		524		359		197		—		556
Non-U.S. equity:
Large Cap	313		68		—		381		253		58		—		311
Other	228		167		—		395		190		81		—		271
Fixed income:
Corporate debt instruments	27		1,026		—		1,053		36		834		—		870
U.S. Treasury securities and agency debentures	331		304		—		635		304		392		—		696
State and municipal	1		71		—		72		2		77		—		79
Other securities	5		43		—		48		8		40		—		48
Real estate:
REITs	29		—		—		29		16		—		—		16
Partnerships	—		—		321		321		—		—		304		304
Other alternative investments:
Private equity	—		—		456		456		—		—		448		448
Debt	—		—		192		192		—		—		243		243
Hedge funds	—		—		221		221		—		—		290		290
Total	$	2,286	$	2,077	$	1,190	$	5,553	$	1,974	$	1,886	$	1,285	$	5,145

The fair values of Dominion's other postretirement plan assets by asset category are as follows:

	Fair Value Measurements
	Other Postretirement Plans
At December 31,	2012								2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	—	$	13	$	—	$	13	$	—	$	5	$	—	$	5
U.S. equity:
Large Cap	378		5		—		383		38		288		—		326
Other	21		45		—		66		17		44		—		61
Non-U.S. equity:
Large Cap	93		3		—		96		77		3		—		80
Other	11		8		—		19		9		4		—		13
Fixed income:
Corporate debt instruments	1		160		—		161		2		149		—		151
U.S. Treasury securities and agency debentures	16		266		—		282		14		246		—		260
State and municipal	—		9		—		9		—		6		—		6
Other securities	—		2		—		2		—		2		—		2
Real estate:
REITs	1		—		—		1		1		—		—		1
Partnerships	—		—		24		24		—		—		24		24
Other alternative investments:
Private equity	—		—		58		58		—		—		63		63
Debt	—		—		31		31		—		—		36		36
Hedge funds	—		—		11		11		—		—		14		14
Total	$	521	$	511	$	124	$	1,156	$	158	$	747	$	137	$	1,042

Pension plan and other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category

The following table presents the changes in Dominion's pension and other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category:

	Fair Value Measurements using Significant Unobservable Inputs (Level 3)
	Pension Plans															Other Postretirement Plans
	Real Estate			Private Equity			Debt			Hedge Funds			Total			Real Estate			Private Equity			Debt			Hedge Funds			Total
Balance at December 31, 2009	$	344		$	344		$	241		$	388		$	1,317		$	26		$	54		$	36		$	19		$	135
Actual return on plan assets:
Relating to assets still held at the reporting date	8			56			27			27			118			—			9			2			1			12
Purchases	56			90			36			—			182			3			9			8			—			20
Sales	(137		)	(90		)	(42		)	(70		)	(339		)	(7		)	(11		)	(6		)	(3		)	(27		)
Balance at December 31, 2010	$	271		$	400		$	262		$	345		$	1,278		$	22		$	61		$	40		$	17		$	140
Actual return on plan assets:
Relating to assets still held at the reporting date	38			70			10			10			128			3			11			1			—			15
Relating to assets sold during the period	(8		)	(34		)	(10		)	(15		)	(67		)	—			(4		)	(1		)	(1		)
Purchases	57			76			34			48			215			3			8			3			2			16
Sales	(54		)	(64		)	(53		)	(98		)	(269		)	(4		)	(13		)	(7		)	(4		)	(28		)
Balance at December 31, 2011	$	304		$	448		$	243		$	290		$	1,285		$	24		$	63		$	36		$	14		$	137
Actual return on plan assets:
Relating to assets still held at the reporting date	21			46			17			21			105			1			3			4			1			9
Relating to assets sold during the period	(8		)	(41		)	(11		)	(2		)	(62		)	—			(1		)	—			—			(1		)
Purchases	35			79			15			—			129			2			6			1			—			9
Sales	(31		)	(76		)	(72		)	(88		)	(267		)	(3		)	(13		)	(10		)	(4		)	(30		)
Balance at December 31, 2012	$	321		$	456		$	192		$	221		$	1,190		$	24		$	58		$	31		$	11		$	124

Net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities

The components of the provision for net periodic benefit cost and amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2012			2011			2010			2012			2011			2010
(millions, except percentages)
Service cost	$	116		$	108		$	102		$	44		$	48		$	56
Interest cost	268			258			266			79			94			101
Expected return on plan assets	(430		)	(440		)	(410		)	(79		)	(79		)	(69		)
Amortization of prior service (credit) cost	3			3			3			(13		)	(13		)	(7		)
Amortization of net actuarial loss	132			96			59			6			12			12
Settlements and curtailments(1)	—			—			136			(4		)	1			37
Special termination benefits(2)	—			—			10			—			—			1
Net periodic benefit (credit) cost	$	89		$	25		$	166		$	33		$	63		$	131
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	786		$	534		$	95		$	139		$	(157	)	$	13
Prior service (credit) cost	—			—			1			1			(70		)	—
Settlements and curtailments(1)	—			—			(50		)	(2		)	(1		)	(1		)
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss	(132		)	(96		)	(59		)	(6		)	(12		)	(12		)
Amortization of prior service credit (cost)	(3		)	(3		)	(3		)	13			13			7
Total recognized in other comprehensive income and regulatory assets and liabilities	$	651		$	435		$	(16	)	$	145		$	(227	)	$	7
Significant assumptions used to determine periodic cost:
Discount rate	5.5		%	5.9		%	6.6		%	5.5		%	5.9		%	6.6		%
Expected long-term rate of return on plan assets	8.5		%	8.5		%	8.5		%	7.75		%	7.75		%	7.75		%
Weighted average rate of increase for compensation	4.21		%	4.61		%	4.76		%	4.22		%	4.62		%	4.79		%
Healthcare cost trend rate(3)										7		%	7		%	7		%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(3)										4.6		%	4.6		%	4.6		%
Year that the rate reaches the ultimate trend rate(3)										2061			2060			2060

(1) 2012 amounts relate to the sale of Salem Harbor. 2010 amounts relate to the sales of Peoples and Dominion's Appalachian E&P operations and a workforce reduction program.

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

(3) Assumptions used to determine periodic cost for the following year.

Components of AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit (credit) cost

The components of AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit cost are as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2012		2011		2012			2011
(millions)
Net actuarial loss	$	2,865	$	2,211	$	230		$	100
Prior service (credit) cost	11		14		(71		)	(86		)
Total(1)	$	2,876	$	2,225	$	159		$	14

(1) As of December 31, 2012, of the $2.9 billion and $158 million related to pension benefits and other postretirement benefits, $1.8 billion and$69 million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2011, of the $2.2 billion related to pension benefits, $1.4 billion is included in AOCI, with the remainder included in regulatory assets and liabilities; the $14 million related to other postretirement benefits consists of $16 million included in regulatory assets and liabilities and $(2) million included in AOCI.

Components of AOCI and regulatory assets and liabilities that are expected to be amortized as components of periodic benefit cost in 2011

The following table provides the components of AOCI and regulatory assets and liabilities as of December 31, 2012 that are expected to be amortized as components of periodic benefit cost in 2013:

	Pension Benefits		Other Postretirement Benefits
(millions)
Net actuarial loss	$	185	$	9
Prior service (credit) cost	3		(12		)

Effect of one percentage point change on benefit plans

A one percentage point change in assumed healthcare cost trend rates would have had the following effects:

	Other Postretirement Benefits
	One percentage point increase		One percentage point decrease
(millions)
Effect on total of service and interest cost components for 2012	$	17	$	(16	)
Effect on other postretirement benefit obligation at December 31, 2012	218		(172		)

XML

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities

Regulatory assets and liabilities include the following:

At December 31,	2012		2011
(millions)
Dominion
Regulatory assets:
Unrecovered gas costs(1)	$	59	$	48
Deferred rate adjustment clause costs(2)	55		113
Virginia sales taxes(3)	37		32
Plant retirement(4)	25		27
Deferred cost of fuel used in electric generation(5)	—		249
Derivatives(6)	—		45
Other	27		27
Regulatory assets-current	203		541
Unrecognized pension and other postretirement benefit costs(7)	1,210		887
Deferred rate adjustment clause costs(2)	173		107
Income taxes recoverable through future rates(8)	140		121
Derivatives(6)	105		49
Other postretirement benefit costs(9)	21		26
Plant retirement(4)	11		25
Deferred cost of fuel used in electric generation(5)	—		122
Other	57		45
Regulatory assets-non-current	1,717		1,382
Total regulatory assets	$	1,920	$	1,923
Regulatory liabilities:
PIPP(10)	$	100	$	58
Provision for rate proceedings(11)	8		150
Other	28		35
Regulatory liabilities-current	136		243
Provision for future cost of removal and AROs(12)	985		901
Decommissioning trust(13)	501		399
Other	28		24
Regulatory liabilities-non-current	1,514		1,324
Total regulatory liabilities	$	1,650	$	1,567
Virginia Power
Regulatory assets:
Deferred rate adjustment clause costs(2)	$	51	$	113
Virginia sales taxes(3)	37		32
Plant retirement(4)	25		27
Deferred cost of fuel used in electric generation(5)	—		249
Derivatives(6)	—		45
Other	6		13
Regulatory assets-current	119		479
Deferred rate adjustment clause costs(2)	127		70
Income taxes recoverable through future rates(8)	110		100
Derivatives(6)	105		49
Plant retirement(4)	11		25
Deferred cost of fuel used in electric generation(5)	—		122
Other	43		33
Regulatory assets-non-current	396		399
Total regulatory assets	$	515	$	878
Regulatory liabilities:
Provision for rate proceedings(11)	$	7	$	150
Other	25		28
Regulatory liabilities-current	32		178

Provision for future cost of removal(12)	763		687
Decommissioning trust(13)	501		399
Other	21		9
Regulatory liabilities-non-current	1,285		1,095
Total regulatory liabilities	$	1,317	$	1,273

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

(2) Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for more information.

(3) Amounts to be recovered through an annual surcharge to reimburse Virginia Power for incremental sales taxes being incurred due to the repeal of the public service company sales tax exemption in Virginia.

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

(5) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power's generation operations. See Note 13 for more information.

(6) As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

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

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

(9) Primarily reflects costs recognized in excess of amounts included in regulated rates charged by Dominion's regulated gas operations before rates were updated to reflect a change in accounting method for other postretirement benefit costs.

(10) Under PIPP, eligible customers can receive energy assistance based on their ability to pay. The difference between the customer's total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rider according to East Ohio tariff provisions. See Note 13 for more information regarding PIPP.

(11) Reflects a reserve associated with the Biennial Review Order. See Note 13 for more information.

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

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

XML

Employee Benefit Plans (Components of AOCI and Regulatory Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 132	$ 96	$ 59
Prior service (credit) cost	3	3	3
Pension Benefits | Scenario, Forecast
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	185
Prior service (credit) cost	3
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	6	12	12
Prior service (credit) cost	(13)	(13)	(7)
Other Postretirement Plans | Scenario, Forecast
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	9
Prior service (credit) cost	$ (12)

XML

Fair Value Measurements (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended		3 Months Ended			1 Months Ended		12 Months Ended	3 Months Ended				3 Months Ended	12 Months Ended	1 Months Ended	3 Months Ended			12 Months Ended
	Mar. 31, 2010	Dec. 31, 2012	Dec. 31, 2012 Kewaunee Utility	Jun. 30, 2012 Salem Harbor	Dec. 31, 2012 Fair Value, Measurements, Nonrecurring Kewaunee	Jun. 30, 2010 Fair Value, Measurements, Nonrecurring State Line	Mar. 31, 2011 Fair Value, Measurements, Nonrecurring State Line Other operations and maintenance expense	Jun. 30, 2010 Fair Value, Measurements, Nonrecurring State Line Other operations and maintenance expense	Dec. 31, 2011 Fair Value, Measurements, Nonrecurring Salem Harbor Other operations and maintenance expense	Sep. 30, 2012 Fair Value, Measurements, Nonrecurring Emissions allowances Other operations and maintenance expense	Mar. 31, 2011 Maximum Fair Value, Measurements, Nonrecurring State Line	Dec. 31, 2011 Maximum Fair Value, Measurements, Nonrecurring Salem Harbor	Sep. 30, 2012 Maximum Fair Value, Measurements, Nonrecurring Emissions allowances	Mar. 31, 2010 Virginia Electric and Power Company	Dec. 31, 2011 Virginia Electric and Power Company	Sep. 30, 2010 Virginia Electric and Power Company Fair Value, Measurements, Nonrecurring Emissions allowances Other operations and maintenance expense	Sep. 30, 2012 Virginia Electric and Power Company Fair Value, Measurements, Nonrecurring Emissions allowances Other operations and maintenance expense	Sep. 30, 2011 Virginia Electric and Power Company Maximum Fair Value, Measurements, Nonrecurring Emissions allowances	Dec. 31, 2012 Elwood	Dec. 31, 2012 Brayton Point Fair Value, Measurements, Nonrecurring	Dec. 31, 2012 Brayton Point Fair Value, Measurements, Nonrecurring Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Ownership percentage																			50.00%
Impairment charge		$ 2,100			$ 378															$ 1,600
Impairment and other charges, net of tax					281															1,000
Long lived assets estimated fair value																					216
Number of utilities			2
Impairment and other charges					435
Long-lived assets impairment charges, net of tax					244
Inventory write-down					33
Inventory write down, net of tax					21
Severance costs	206				24									123
Severance costs net of tax					16
Impairment charge							55	163	31						228
Other Asset Impairment Charges Net Of Tax							39	107	20
Estimated fair value						59					1	1
After tax charge on disposal of assets				27
Pretax charge on disposal of assets				16
Salem Harbor, impairment charge										57						13	43
Impairment charge after tax																8
So2 emissions allowances obtained for arp cnd cair compliance										57							43
Impairment of intangible assets after tax										34							26
Maximum fair value of So2 emissions allowances													$ 1					$ 1

XML

Commitments and Contingencies (MF Global) (Details) (MF Global Bankruptcy, USD $) In Millions, unless otherwise specified	12 Months Ended		3 Months Ended
	Dec. 31, 2012	Oct. 31, 2011	Mar. 31, 2013 Subsequent Event
Loss Contingencies [Line Items]
Initial margin posted		$ 73
Margin received to date	17
Remaining margin claims sold to 3rd party			$ 56

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Loss Contingencies [Line Items]

Lease Commitments

Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2012 are as follows:

	2013		2014		2015		2016		2017		Thereafter		Total
(millions)
Dominion	$	79	$	72	$	64	$	55	$	63	$	161	$	494
Virginia Power	$	26	$	24	$	19	$	15	$	11	$	26	$	121

Nuclear Insurance

The current level of property insurance coverage for Dominion's and Virginia Power's nuclear units is as follows:

	Coverage
(billions)
Dominion
Millstone	$	2.75
Kewaunee	1.80
Virginia Power(1)
Surry	$	2.55
North Anna	2.55

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

Subsidiary guarantees

At December 31, 2012, Dominion had issued the following subsidiary guarantees:

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	363	$	363
Commodity transactions(3)	2,939		377
Nuclear obligations(4)	231		77
Other(5)	673		98
Total	$	4,206	$	915

(1) Represents the estimated portion of the guarantee's stated limit that is utilized as of December 31, 2012 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

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

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

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

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

Virginia Electric and Power Company

Loss Contingencies [Line Items]

Long-term Purchase Commitment

At December 31, 2012, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:

	2013		2014		2015		2016		2017		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	350	$	358	$	337	$	275	$	181	$	327	$	1,828

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2012, the present value of Virginia Power's total commitment for capacity payments is $1.4 billion. Capacity payments totaled $337 million, $338 million, and $344 million, and energy payments totaled $214 million, $275 million, and $303 million for 2012, 2011 and 2010, respectively.

XML

Derivatives and Hedge Accounting Activities (Selected Information Related to Gains (Losses) on Cash Flow Hedges Included in AOCI) (Details) (USD $) In Millions, unless otherwise specified			12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Commodity Gas	Dec. 31, 2012 Commodity Electricity	Dec. 31, 2012 Commodity Other	Dec. 31, 2012 Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ (122)	$ (54)	$ (28)	$ 68	$ 3	$ (165)
Amounts expected to be reclassified to earnings during the next 12 months after-tax	$ (26)		$ (24)	$ 17	$ 2	$ (21)
Maximum Term			27 months	36 months	41 months	361 months

XML

Long-Term Debt (Based on Stated Maturity Dates Rather than Early Redemption Dates that Could be Elected by Instrument Holders) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Debt Instrument [Line Items]
2013	$ 2,200
2014	1,080
2015	978
2016	1,390
2017	1,400
Thereafter	11,940
Total	18,988
Virginia Electric and Power Company
Debt Instrument [Line Items]
2013	418
2014	17
2015	211
2016	476
2017	679
Thereafter	4,875
Total	6,676
2013
Debt Instrument [Line Items]
Weighted-average Coupon	4.53%
2013 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	4.88%
2014
Debt Instrument [Line Items]
Weighted-average Coupon	3.99%
2014 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	7.73%
2015
Debt Instrument [Line Items]
Weighted-average Coupon	4.50%
2015 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	5.39%
2016
Debt Instrument [Line Items]
Weighted-average Coupon	4.27%
2016 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	5.27%
2017
Debt Instrument [Line Items]
Weighted-average Coupon	4.60%
2017 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	5.44%
Thereafter
Debt Instrument [Line Items]
Weighted-average Coupon	5.54%
Thereafter | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	5.26%
Secured Senior Notes
Debt Instrument [Line Items]
2013	852
2014	15
2015	18
2016	20
2017	22
Thereafter	60
Total	987
Unsecured Senior Notes
Debt Instrument [Line Items]
2013	1,090
2014	1,065
2015	960
2016	1,351
2017	1,303
Thereafter	9,278
Total	15,047
Tax-Exempt Financings
Debt Instrument [Line Items]
2013	0
2014	0
2015	0
2016	19
2017	75
Thereafter	1,227
Total	1,321
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts
Debt Instrument [Line Items]
2013	258
2014	0
2015	0
2016	0
2017	0
Thereafter	10
Total	268
Enhanced Junior Subordinated Notes
Debt Instrument [Line Items]
2013	0
2014	0
2015	0
2016	0
2017	0
Thereafter	1,365
Total	$ 1,365

XML

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment, Net [Abstract]

Property, Plant and Equipment

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:

At December 31,	2012		2011
(millions)
Dominion
Utility:
Generation	$	13,707	$	11,793
Transmission	7,799		6,604
Distribution	11,071		10,401
Storage	2,137		2,060
Nuclear fuel	1,277		1,193
Gas gathering and processing	803		727
General and other	803		778
Other-including plant under construction	2,232		3,597
Total utility	39,829		37,153
Nonutility:
Merchant generation-nuclear	1,163		1,108
Merchant generation-other(1)	1,289		2,780
Nuclear fuel	775		847
Other-including plant under construction	1,265		1,102
Total nonutility	4,492		5,837
Total property, plant and equipment	$	44,321	$	42,990
Virginia Power
Utility:
Generation	$	13,707	$	11,793
Transmission	4,261		3,823
Distribution	8,701		8,231
Nuclear fuel	1,277		1,193
General and other	659		631
Other-including plant under construction	2,017		2,946
Total utility	30,622		28,617
Nonutility-other	9		9
Total property, plant and equipment	$	30,631	$	28,626

(1) Amount includes $957 million due to consolidation of a VIE.

Share of Jointly-Owned Power Stations

Dominion's and Virginia Power's proportionate share of jointly-owned power stations at December 31, 2012 is as follows:

	Bath County Pumped Storage Station(1)			North Anna Units 1 and 2(1)			Clover Power Station(1)			Millstone Unit 3(2)
(millions, except percentages)
Ownership interest	60		%	88.4		%	50		%	93.5		%
Plant in service	$	1,024		$	2,392		$	568		$	993
Accumulated depreciation	(521		)	(1,072		)	(192		)	(236		)
Nuclear fuel	—			502			—			456
Accumulated amortization of nuclear fuel	—			(390		)	—			(272		)
Plant under construction	27			77			6			36

(1) Units jointly owned by Virginia Power.

(2) Unit jointly owned by Dominion.

XML

Credit Risk

12 Months Ended

Dec. 31, 2012

Risks and Uncertainties [Abstract]

Credit Risk

. CREDIT RISK

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

Dominion and Virginia Power maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 2012 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

GENERAL

DOMINION

As a diversified energy company, Dominion transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.

Dominion's exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include trading of energy-related commodities, marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2012, Dominion's credit exposure totaled $512 million. Of this amount, investment grade counterparties, including those internally rated, represented 77%. One counterparty exposure represents 11% of Dominion's total exposure and is a large financial institution rated investment grade.

VIRGINIA POWER

Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power's customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power's exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power's gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2012, Virginia Power's exposure to potential concentrations of credit risk was not considered material.

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 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 December 31, 2012 and 2011, Dominion would have been required to post an additional $110 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 $4 million in collateral at December 31, 2012 and $110 million in collateral, including $4 million of letters of credit at December 31, 2011, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 2012 and 2011 was $163 million and $259 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power were not material as of December 31, 2012 and 2011. See Note 7 for further information about derivative instruments.

XML

Derivatives and Hedge Accounting Activities (Fair Values of our Derivatives) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	$ 828		$ 1,070
Total Fair Value, Liabilities	661		1,157
Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	518		705
Current Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	482		671
Current Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	36		34
Noncurrent Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	310		365	[1]
Noncurrent Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	253		294
Noncurrent Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	57		71
Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	510		951
Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	444		692
Current Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	66		259
Noncurrent Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	151		206	[2]
Noncurrent Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	151		196
Noncurrent Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			10
Fair Value - Derivatives under Hedge Accounting
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	326		479
Total Fair Value, Liabilities	227		502
Fair Value - Derivatives under Hedge Accounting | Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	139		210
Fair Value - Derivatives under Hedge Accounting | Current Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	103		176
Fair Value - Derivatives under Hedge Accounting | Current Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	36		34
Fair Value - Derivatives under Hedge Accounting | Noncurrent Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	187		269	[1]
Fair Value - Derivatives under Hedge Accounting | Noncurrent Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	130		198
Fair Value - Derivatives under Hedge Accounting | Noncurrent Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	57		71
Fair Value - Derivatives under Hedge Accounting | Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	169		384
Fair Value - Derivatives under Hedge Accounting | Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	103		162
Fair Value - Derivatives under Hedge Accounting | Current Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	66		222
Fair Value - Derivatives under Hedge Accounting | Noncurrent Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	58		118	[2]
Fair Value - Derivatives under Hedge Accounting | Noncurrent Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	58		118
Fair Value - Derivatives under Hedge Accounting | Noncurrent Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			0
Fair Value - Derivatives not under Hedge Accounting
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	502		591
Total Fair Value, Liabilities	434		655
Fair Value - Derivatives not under Hedge Accounting | Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	379		495
Fair Value - Derivatives not under Hedge Accounting | Current Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	379		495
Fair Value - Derivatives not under Hedge Accounting | Current Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	0		0
Fair Value - Derivatives not under Hedge Accounting | Noncurrent Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	123		96	[1]
Fair Value - Derivatives not under Hedge Accounting | Noncurrent Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	123		96
Fair Value - Derivatives not under Hedge Accounting | Noncurrent Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	0		0
Fair Value - Derivatives not under Hedge Accounting | Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	341		567
Fair Value - Derivatives not under Hedge Accounting | Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	341		530
Fair Value - Derivatives not under Hedge Accounting | Current Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	0		37
Fair Value - Derivatives not under Hedge Accounting | Noncurrent Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	93		88	[2]
Fair Value - Derivatives not under Hedge Accounting | Noncurrent Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	93		78
Fair Value - Derivatives not under Hedge Accounting | Noncurrent Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			10
Virginia Electric and Power Company
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	6		2
Total Fair Value, Liabilities	34		147
Virginia Electric and Power Company | Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	6	[3]	2	[3]
Virginia Electric and Power Company | Current Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	6		2
Virginia Electric and Power Company | Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	33		135
Virginia Electric and Power Company | Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	8		45
Virginia Electric and Power Company | Current Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	25		90
Virginia Electric and Power Company | Noncurrent Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	1	[4]	12	[4]
Virginia Electric and Power Company | Noncurrent Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	1		2
Virginia Electric and Power Company | Noncurrent Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			10
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	1		0
Total Fair Value, Liabilities	31		69
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	1	[3]	0	[3]
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Current Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	1		0
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	30		67
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	5		14
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Current Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	25		53
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Noncurrent Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	1	[4]	2	[4]
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Noncurrent Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	1		2
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Noncurrent Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			0
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	5		2
Total Fair Value, Liabilities	3		78
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting | Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	5	[3]	2	[3]
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting | Current Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	5		2
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting | Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	3		68
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting | Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	3		31
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting | Current Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	0		37
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting | Noncurrent Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	0	[4]	10	[4]
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting | Noncurrent Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	0		0
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting | Noncurrent Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			$ 10

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

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

[3] Current derivative assets are presented in other current assets in Virginia Power's Consolidated Balance Sheets.

[4] Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power's Consolidated Balance Sheets.

XML

Employee Benefit Plans (Pension plan and other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category) (Details) (Level 3, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Benefits
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$ 1,285	$ 1,278	$ 1,317
Actual return on plan assets:
Relating to assets still held at the reporting date	105	128	118
Relating to assets sold during the period	(62)	(67)
Purchases	129	215	182
Sales	(267)	(269)	(339)
Fair value of plan assets at end of year	1,190	1,285	1,278
Pension Benefits | Real estate:
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	304	271	344
Actual return on plan assets:
Relating to assets still held at the reporting date	21	38	8
Relating to assets sold during the period	(8)	(8)
Purchases	35	57	56
Sales	(31)	(54)	(137)
Fair value of plan assets at end of year	321	304	271
Pension Benefits | Private equity
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	448	400	344
Actual return on plan assets:
Relating to assets still held at the reporting date	46	70	56
Relating to assets sold during the period	(41)	(34)
Purchases	79	76	90
Sales	(76)	(64)	(90)
Fair value of plan assets at end of year	456	448	400
Pension Benefits | Debt
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	243	262	241
Actual return on plan assets:
Relating to assets still held at the reporting date	17	10	27
Relating to assets sold during the period	(11)	(10)
Purchases	15	34	36
Sales	(72)	(53)	(42)
Fair value of plan assets at end of year	192	243	262
Pension Benefits | Hedge funds
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	290	345	388
Actual return on plan assets:
Relating to assets still held at the reporting date	21	10	27
Relating to assets sold during the period	(2)	(15)
Purchases	0	48	0
Sales	(88)	(98)	(70)
Fair value of plan assets at end of year	221	290	345
Other Postretirement Plans
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	137	140	135
Actual return on plan assets:
Relating to assets still held at the reporting date	9	15	12
Relating to assets sold during the period	(1)
Purchases	9	16	20
Sales	(30)	(28)	(27)
Fair value of plan assets at end of year	124	137	140
Other Postretirement Plans | Real estate:
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	24	22	26
Actual return on plan assets:
Relating to assets still held at the reporting date	1	3	0
Relating to assets sold during the period	0	0
Purchases	2	3	3
Sales	(3)	(4)	(7)
Fair value of plan assets at end of year	24	24	22
Other Postretirement Plans | Private equity
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	63	61	54
Actual return on plan assets:
Relating to assets still held at the reporting date	3	11	9
Relating to assets sold during the period	(1)	(4)
Purchases	6	8	9
Sales	(13)	(13)	(11)
Fair value of plan assets at end of year	58	63	61
Other Postretirement Plans | Debt
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	36	40	36
Actual return on plan assets:
Relating to assets still held at the reporting date	4	1	2
Relating to assets sold during the period	0	(1)
Purchases	1	3	8
Sales	(10)	(7)	(6)
Fair value of plan assets at end of year	31	36	40
Other Postretirement Plans | Hedge funds
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	14	17	19
Actual return on plan assets:
Relating to assets still held at the reporting date	1	0	1
Relating to assets sold during the period	0	(1)
Purchases	0	2	0
Sales	(4)	(4)	(3)
Fair value of plan assets at end of year	$ 11	$ 14	$ 17

XML

Commitments and Contingencies (Lease Commitments) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Loss Contingencies [Line Items]
Rental expense	$ 112	$ 155	$ 171
Virginia Electric and Power Company
Loss Contingencies [Line Items]
Rental expense	$ 48	$ 50	$ 50

XML

Credit Risk (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Concentration Risk [Line Items]
Gross credit exposure	$ 512
Additional collateral to be posted if the credit-related contingent features were triggered	110	88
Collateral already posted	4	110
Letters of credit included in the collateral posted		4
Fair value of all derivative instruments not fully collateralized	$ 163	$ 259
Investment Grade | Internal Credit Rating
Concentration Risk [Line Items]
Concentration of credit risk	77.00%
Investment Grade | CounterpartyA
Concentration Risk [Line Items]
Concentration of credit risk	11.00%

XML

Fair Value Measurements (Net Change in the Assets and Liabilities Measured at Fair Value on a Recurrring Basis and Included in the Level 3 Fair Value Category) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation [Roll Forward]
Included in earnings	$ (15)	$ (77)	$ 43
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	42	22	(4)
Commodity | Level 3
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation [Roll Forward]
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	42	22	(4)
Commodity | Level 3 | Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation [Roll Forward]
Beginnning balance	(71)	(50)	(66)
Included in earnings	(15)	(77)	43
Included in other comprehensive income (loss)	101	14	(49)
Included in regulatory assets/liabilities	30	(42)	24
Settlements	47	88	(38)
Transfers out of Level 3	67	4	(36)
Ending balance	25	(71)	(50)
Commodity | Virginia Electric and Power Company | Level 3 | Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation [Roll Forward]
Beginnning balance	(28)	14	(10)
Included in earnings	(50)	(45)	51
Included in regulatory assets/liabilities	30	(42)	24
Settlements	50	45	(51)
Transfers out of Level 3	0	0	0
Ending balance	$ 2	$ (28)	$ 14

XML

Property, Plant and Equipment (Property, Plant and Equipment) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Utility:
Generation	$ 13,707		$ 11,793
Transmission	7,799		6,604
Distribution	11,071		10,401
Storage	2,137		2,060
Nuclear fuel	1,277		1,193
Gas gathering and processing	803		727
General and other	803		778
Other-including plant under construction	2,232		3,597
Total utility	39,829		37,153
Nonutility:
Merchant generation-nuclear	1,163		1,108
Merchant generation-other	1,289	[1]	2,780	[1]
Nuclear fuel	775		847
Other-including plant under construction	1,265		1,102
Total nonutility	4,492		5,837
Total property, plant and equipment	44,321		42,990
Merchant generation other, due to consolidation of VIE	957
Virginia Electric and Power Company
Utility:
Generation	13,707		11,793
Transmission	4,261		3,823
Distribution	8,701		8,231
Nuclear fuel	1,277		1,193
General and other	659		631
Other-including plant under construction	2,017		2,946
Total utility	30,622		28,617
Nonutility:
Total nonutility	9		9
Total property, plant and equipment	$ 30,631		$ 28,626

[1] Amount includes $957 million due to consolidation of a VIE.

XML

Operating Segments (Tables)

12 Months Ended

Dec. 31, 2012

Segment Reporting Information [Line Items]

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 and storage	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:

Year Ended December 31,	DVP		Dominion Generation(1)		Dominion Energy		Corporate and Other(1)			Adjustments & Eliminations			Consolidated Total
(millions)
2012
Total revenue from external customers	$	3,385	$	6,517	$	1,813	$	307		$	1,071		$	13,093
Intersegment revenue	112		333		930		608			(1,983		)	—
Total operating revenue	3,497		6,850		2,743		915			(912		)	13,093
Depreciation, depletion and amortization	402		500		216		68			—			1,186
Equity in earnings of equity method investees	—		3		23		(1		)	—			25
Interest income	9		57		30		71			(106		)	61
Interest and related charges	187		208		47		546			(106		)	882
Income taxes	351		479		352		(1,036		)	—			146
Loss from discontinued operations, net of tax	—		—		—		(22		)	—			(22		)
Net income (loss) attributable to Dominion	559		874		551		(1,682		)	—			302
Investment in equity method investees	1		414		141		2			—			558
Capital expenditures	1,158		1,615		1,350		22			—			4,145
Total assets (billions)	12.1		21.2		11.2		12.6			(10.3		)	46.8
2011
Total revenue from external customers	$	3,663	$	7,080	$	2,044	$	55		$	1,303		$	14,145
Intersegment revenue	173		355		1,077		596			(2,201		)	—
Total operating revenue	3,836		7,435		3,121		651			(898		)	14,145
Depreciation, depletion and amortization	374		457		207		28			—			1,066
Equity in earnings of equity method investees	—		3		23		9			—			35
Interest income	22		54		27		70			(106		)	67
Interest and related charges	185		217		57		514			(106		)	867
Income taxes	318		583		323		(470		)	—			754
Loss from discontinued operations, net of tax	—		—		—		(25		)	—			(25		)
Net income (loss) attributable to Dominion	501		968		521		(582		)	—			1,408
Investment in equity method investees	8		415		104		26			—			553
Capital expenditures	1,091		1,593		907		61			—			3,652
Total assets (billions)	11.5		22.1		10.6		11.4			(10.0		)	45.6
2010
Total revenue from external customers	$	3,613	$	7,735	$	2,335	$	19		$	1,225		$	14,927
Intersegment revenue	207		413		1,166		750			(2,536		)	—
Total operating revenue	3,820		8,148		3,501		769			(1,311		)	14,927
Depreciation, depletion and amortization	353		443		210		29			—			1,035
Equity in earnings of equity method investees	—		11		21		10			—			42
Interest income	12		45		12		92			(90		)	71
Interest and related charges	158		179		85		494			(90		)	826
Income taxes	277		756		302		777			—			2,112
Loss from discontinued operations, net of tax	—		—		—		(258		)	—			(258		)
Net income attributable to Dominion	448		1,263		475		622			—			2,808
Capital expenditures	1,038		1,742		613		29			—			3,422

(1) Segment information has been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

Virginia Electric and Power Company

Segment Reporting Information [Line Items]

Segment Reporting Disclosure Other Information

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

Year Ended December 31,	DVP		Dominion Generation		Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2012
Operating revenue	$	1,847	$	5,379	$	—		$	—		$	7,226
Depreciation and amortization	392		390		—			—			782
Interest income	1		7		—			—			8
Interest and related charges	186		199		—			—			385
Income taxes	277		403		(27		)	—			653
Net income (loss)	448		653		(51		)	—			1,050
Capital expenditures	1,142		1,146		—			—			2,288
Total assets (billions)	11.4		14.8		—			(1.4		)	24.8
2011
Operating revenue	$	1,793	$	5,546	$	(93	)	$	—		$	7,246
Depreciation and amortization	368		350		—			—			718
Interest income	10		8		—			—			18
Interest and related charges	182		199		(50		)	—			331
Income taxes	265		447		(172		)	—			540
Net income (loss)	426		664		(268		)	—			822
Capital expenditures	1,081		1,009		—			—			2,090
Total assets (billions)	10.7		14.3		—			(1.5		)	23.5
2010
Operating revenue	$	1,680	$	5,546	$	(7	)	$	—		$	7,219
Depreciation and amortization	344		327		—			—			671
Interest income	11		4		—			—			15
Interest and related charges	158		189		—			—			347
Income taxes	228		385		(71		)	—			542
Net income (loss)	377		630		(155		)	—			852
Capital expenditures	1,035		1,199		—			—			2,234

XML

Shareholders' Equity (Accumulated Other Comprehensive Income (Loss)) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Net unrealized gains on derivatives-hedging activities, net of tax	$ (122)	$ (54)
Net unrealized gains on nuclear decommissioning trust funds, net of tax	326	243
Net unrecognized pension and other postretirement benefit costs, net of tax	(1,081)	(799)
Total AOCI	(877)	(610)
Net unrealized gains (losses) on derivatives-hedging activities, tax	87	48
Net unrealized gains (losses) on nuclear decommissioning trust funds, tax	(206)	(154)
Net unrecognized pension and other postretirement benefit costs, tax	754	568
Virginia Electric and Power Company
Net unrealized gains on derivatives-hedging activities, net of tax	(6)	(3)
Net unrealized gains on nuclear decommissioning trust funds, net of tax	31	22
Total AOCI	25	19
Net unrealized gains (losses) on derivatives-hedging activities, tax	3	2
Net unrecognized pension and other postretirement benefit costs, tax	$ (19)	$ (14)

XML

Related Party Transactions (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
Issuance of common stock		$ 265	$ 38	$ 74
Virginia Electric and Power Company
Related Party Transaction [Line Items]
Commodity purchases from affiliates		368	376	373
Services provided by affiliates		399	393	469
Services provided to affiliates		19	21	19
Purchased nuclear fuel-related inventory	39
Outstanding borrowings, net of repayments, under the Dominion money pool for Virginia Power's nonregulated subsidiaries	187	192	187
Common stock issued (shares)				33,013
Issuance of common stock				1,000
Dominion | Virginia Electric and Power Company
Related Party Transaction [Line Items]
Other Short-term Borrowings		$ 243

XML

Derivatives And Hedge Accounting Activities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 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
Fair value of AOCI earnings, partially offset by subsequent changes, after-tax	$ 23

XML

Investments (Selected Information Regarding Marketable Equity and Debt Securities) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Available-for-sale securities:
Proceeds from sales	$ 1,356,000,000		$ 1,757,000,000		$ 1,814,000,000	[1]
Realized gains	98,000,000	[2]	79,000,000	[2]	111,000,000	[2]
Realized losses	33,000,000	[2]	92,000,000	[2]	63,000,000	[2]
Proceeds from sale of investments			1,000,000,000
Virginia Electric and Power Company
Available-for-sale securities:
Proceeds from sales	626,000,000		1,030,000,000		1,192,000,000
Realized gains	42,000,000	[2]	34,000,000	[2]	52,000,000	[2]
Realized losses	$ 11,000,000	[2]	$ 34,000,000	[2]	$ 23,000,000	[2]

[1] Does not include $1 billion of proceeds reflected in Dominion's Consolidated Statement of Cash Flows from the sale of temporary investments consisting of time deposits and Treasury Bills, purchased following the sale of substantially all of Dominion's Appalachian E&P operations.

[2] Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2.

XML

Derivatives and Hedge Accounting Activities (Gains and Losses on our Derivatives Not Designated as Hedging Instruments) (Details) (Derivatives not designated as hedging instruments, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	$ 131	[1]	$ 26	[1]	$ 40	[1]
Commodity | Operating Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	168	[1]	111	[1]	67	[1]
Commodity | Purchased gas
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	(14)	[1]	(35)	[1]	(41)	[1]
Commodity | Electric fuel and other energy-related purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	(40)	[1]	(45)	[1]	51	[1]
Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	17	[1],[2]	(5)	[1],[2]	(37)	[1],[2]
Virginia Electric and Power Company
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	(50)	[3]	(50)	[3]	48	[3]
Virginia Electric and Power Company | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	(50)	[3],[4]	(45)	[3],[4]	51	[3],[4]
Virginia Electric and Power Company | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	$ 0	[3],[5]	$ (5)	[3],[5]	$ (3)	[3],[5]

[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.

[3] 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.

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

[5] Amounts recorded in Virginia Power's Consolidated Statements of Income are classified in interest and related charges.

XML

Investments (Recorded Other-Than-Temporary Impairment Losses on Investments) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Schedule of Available-for-sale Securities [Line Items]
Total other-than-temporary impairment losses	$ 26	[1]	$ 75	[1]	$ 59	[1]
Losses recorded to decommissioning trust regulatory liability	(10)		(24)		(21)
Losses recognized in other comprehensive income (before taxes)	2		3		3
Net impairment losses recognized in earnings	14		48		35
Other-than-temporary impairment losses for debt securities	4		6		10
Virginia Electric and Power Company
Schedule of Available-for-sale Securities [Line Items]
Total other-than-temporary impairment losses	11	[2]	29	[2]	25	[2]
Losses recorded to decommissioning trust regulatory liability	(10)		(24)		(21)
Losses recognized in other comprehensive income (before taxes)	0		1		1
Net impairment losses recognized in earnings	1		4		3
Other-than-temporary impairment losses for debt securities	$ 2		$ 4		$ 6

[1] Amounts include other-than-temporary impairment losses for debt securities of $4 million, $6 million and $10 million at December 31, 2012, 2011 and 2010, respectively.

[2] Amounts include other-than-temporary impairment losses for debt securities of $2 million, $4 million and $6 million at December 31, 2012, 2011 and 2010, respectively.

XML

Derivatives and Hedge Accounting Activities (Volume of our Derivative Activity) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Current
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate	$ 1,500
Current | Natural Gas (bcf): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	249,000,000,000	[1]
Current | Natural Gas (bcf): | Basis
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	786,000,000,000	[1]
Current | Electricity (MWh): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	20,100,938	[1]
Current | Electricity (MWh): | FTRs
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	46,851,683
Current | Capacity (MW)
Derivative Instruments, Gain (Loss) [Line Items]
Capacity of Electricity (in Megawatts)	151,025
Current | Liquids (gallons)
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	164,682,000	[2]
Noncurrent
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate	2,250
Noncurrent | Natural Gas (bcf): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	68,000,000,000	[1]
Noncurrent | Natural Gas (bcf): | Basis
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	534,000,000,000	[1]
Noncurrent | Electricity (MWh): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	12,582,674	[1]
Noncurrent | Electricity (MWh): | FTRs
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	0
Noncurrent | Capacity (MW)
Derivative Instruments, Gain (Loss) [Line Items]
Capacity of Electricity (in Megawatts)	148,461
Noncurrent | Liquids (gallons)
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	145,698,000	[2]
Virginia Electric and Power Company | Current
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate	500,000,000
Virginia Electric and Power Company | Current | Natural Gas (bcf): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	16,000,000,000
Virginia Electric and Power Company | Current | Natural Gas (bcf): | Basis
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	8,000,000,000
Virginia Electric and Power Company | Current | Electricity (MWh): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	709,600,000,000
Virginia Electric and Power Company | Current | Electricity (MWh): | FTRs
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	43,570,739,000,000
Virginia Electric and Power Company | Current | Capacity (MW)
Derivative Instruments, Gain (Loss) [Line Items]
Capacity of Electricity (in Megawatts)	107,000,000,000
Virginia Electric and Power Company | Noncurrent
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate	$ 250,000,000
Virginia Electric and Power Company | Noncurrent | Natural Gas (bcf): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	0
Virginia Electric and Power Company | Noncurrent | Natural Gas (bcf): | Basis
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	0
Virginia Electric and Power Company | Noncurrent | Electricity (MWh): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	0
Virginia Electric and Power Company | Noncurrent | Electricity (MWh): | FTRs
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	0
Virginia Electric and Power Company | Noncurrent | Capacity (MW)
Derivative Instruments, Gain (Loss) [Line Items]
Capacity of Electricity (in Megawatts)	93,800,000,000

[1] Includes options.

[2] Includes NGLs and oil.

XML

Fair Value Measurements (Fair Value, Option, Quantitative Disclosures) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 84,000,000
Derivative liabilities	59,000,000
Gas | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	13,000,000	[1]
Derivative liabilities	18,000,000	[1]
Gas | Physical and Financial Options:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5,000,000
Derivative liabilities	12,000,000	[1]
Electricity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	6,000,000
Derivative liabilities	1,000,000
Electricity | Full Requirements Contracts:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	27,000,000
FTRs | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5,000,000
Derivative liabilities	3,000,000
Capacity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	7,000,000
Liquids | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	21,000,000	[2]
Derivative liabilities	25,000,000	[2]
Fair Value, Option, Quantitative Disclosures, Assets | Minimum | Gas | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	(1)	[3]
Fair Value, Option, Quantitative Disclosures, Assets | Minimum | Gas | Physical and Financial Options:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	3	[3]
Price Volatility	21.00%	[4]
Price Correlation	73.00%	[5]
Fair Value, Option, Quantitative Disclosures, Assets | Minimum | Electricity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	30	[3]
Fair Value, Option, Quantitative Disclosures, Assets | Minimum | Electricity | Full Requirements Contracts:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	8	[3]
Load Shaping	0.00%	[6]
Usage Factor	2.00%	[7]
Fair Value, Option, Quantitative Disclosures, Assets | Minimum | FTRs | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	(6)	[3]
Fair Value, Option, Quantitative Disclosures, Assets | Minimum | Capacity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	95	[3]
Fair Value, Option, Quantitative Disclosures, Assets | Minimum | Liquids | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	0	[3]
Fair Value, Option, Quantitative Disclosures, Assets | Weighted Average | Gas | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	3	[8]
Fair Value, Option, Quantitative Disclosures, Assets | Weighted Average | Gas | Physical and Financial Options:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	4	[8]
Price Volatility	24.00%	[8]
Price Correlation	73.00%	[8]
Fair Value, Option, Quantitative Disclosures, Assets | Weighted Average | Electricity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	50	[8]
Fair Value, Option, Quantitative Disclosures, Assets | Weighted Average | Electricity | Full Requirements Contracts:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	40	[8]
Load Shaping	5.00%	[8]
Usage Factor	8.00%	[8]
Fair Value, Option, Quantitative Disclosures, Assets | Weighted Average | FTRs | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	1	[8]
Fair Value, Option, Quantitative Disclosures, Assets | Weighted Average | Capacity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	101	[8]
Fair Value, Option, Quantitative Disclosures, Assets | Weighted Average | Liquids | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	1	[8]
Fair Value, Option, Quantitative Disclosures, Assets | Maximum | Gas | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	6	[3]
Fair Value, Option, Quantitative Disclosures, Assets | Maximum | Gas | Physical and Financial Options:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	5	[3]
Price Volatility	36.00%	[4]
Price Correlation	73.00%	[5]
Fair Value, Option, Quantitative Disclosures, Assets | Maximum | Electricity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	85	[3]
Fair Value, Option, Quantitative Disclosures, Assets | Maximum | Electricity | Full Requirements Contracts:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	439	[3]
Load Shaping	10.00%	[6]
Usage Factor	16.00%	[7]
Fair Value, Option, Quantitative Disclosures, Assets | Maximum | FTRs | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	7	[3]
Fair Value, Option, Quantitative Disclosures, Assets | Maximum | Capacity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	115	[3]
Fair Value, Option, Quantitative Disclosures, Assets | Maximum | Liquids | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	3	[3]
Fair Value, Option, Quantitative Disclosures, Liabilities | Minimum | Gas | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	(1)	[3]
Fair Value, Option, Quantitative Disclosures, Liabilities | Minimum | Gas | Physical and Financial Options:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	3	[3]
Price Volatility	21.00%	[4]
Price Correlation	99.00%	[5]
Fair Value, Option, Quantitative Disclosures, Liabilities | Minimum | Electricity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	25	[3]
Fair Value, Option, Quantitative Disclosures, Liabilities | Minimum | FTRs | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	(1)	[3]
Fair Value, Option, Quantitative Disclosures, Liabilities | Minimum | Liquids | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	1	[3]
Fair Value, Option, Quantitative Disclosures, Liabilities | Weighted Average | Gas | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	3	[8]
Fair Value, Option, Quantitative Disclosures, Liabilities | Weighted Average | Gas | Physical and Financial Options:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	5	[8]
Price Volatility	32.00%	[8]
Price Correlation	99.00%	[8]
Fair Value, Option, Quantitative Disclosures, Liabilities | Weighted Average | Electricity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	39	[8]
Fair Value, Option, Quantitative Disclosures, Liabilities | Weighted Average | FTRs | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	0	[8]
Fair Value, Option, Quantitative Disclosures, Liabilities | Weighted Average | Liquids | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	2	[8]
Fair Value, Option, Quantitative Disclosures, Liabilities | Maximum | Gas | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	18	[3]
Fair Value, Option, Quantitative Disclosures, Liabilities | Maximum | Gas | Physical and Financial Options:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	8	[3]
Price Volatility	36.00%	[4]
Price Correlation	99.00%	[5]
Fair Value, Option, Quantitative Disclosures, Liabilities | Maximum | Electricity | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	65	[3]
Fair Value, Option, Quantitative Disclosures, Liabilities | Maximum | FTRs | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	18	[3]
Fair Value, Option, Quantitative Disclosures, Liabilities | Maximum | Liquids | Physical and Financial Forwards and Futures:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Market Price	$ 3	[3]

[1] Includes basis.

[2] Includes NGLs

[3] Represents market prices beyond defined terms for Levels 1 & 2.

[4] Represents volatilities unrepresented in published markets.

[5] Represents intra-price correlations for which markets do not exist.

[6] Converts block monthly loads to 24-hour load shapes.

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

[8] Averages weighted by volume.

XML

Variable Interest Entities

12 Months Ended

Dec. 31, 2012

Variable Interest Entities [Abstract]

Variable Interest Entities

VARIABLE INTEREST ENTITIES

The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity's economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.

Virginia Power has long-term power and capacity contracts with four non-utility generators with an aggregate summer generation capacity of approximately 870 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power's knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power's determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power's contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $1.1 billion as of December 31, 2012. Virginia Power paid $214 million, $211 million, and $213 million for electric capacity and $83 million, $125 million, and $164 million for electric energy to these entities for the years ended December 31, 2012, 2011 and 2010, respectively.

Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $328 million, $389 million, and $465 million for the years ended December 31, 2012, 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.

Dominion leases the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. Dominion makes annual lease payments of approximately $53 million. The lease expires in 2013 and, at that time, Dominion may renew the lease on terms mutually agreeable to Dominion and Juniper based on original project costs and current market conditions; purchase Fairless for approximately $923 million or sell Fairless, on behalf of Juniper, to an independent third party. If Fairless is sold and the proceeds from the sale are less than its original construction cost, Dominion would be required to make a payment to the lessor in an amount up to 70.75% of the original project costs adjusted for certain other costs as specified in the lease. The lease agreement does not contain any provisions that involve credit rating or stock price trigger events. Dominion expects to purchase Fairless when the lease expires in the third quarter of 2013.

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 subject to the business scope exception, Dominion was not required to evaluate whether Juniper was a VIE prior to October 2011.

Through September 30, 2011, Juniper held various power plant leases, including Fairless. In October 2011, the last lease other than Fairless expired and the related asset was sold by Juniper. With Fairless being its sole remaining asset, Juniper no longer qualified as a business as of October 2011, which required that Dominion determine whether Juniper 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 is not held by the equity holders, and Dominion, through its residual value guarantee discussed above, 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. The decisions related to the operations of Fairless are made by Dominion and as such, Dominion is considered the primary beneficiary.

Accordingly, Dominion consolidated Juniper in October 2011 and recorded, at fair value, approximately $957 million of property, plant and equipment, $896 million of debt and $61 million of noncontrolling interests. The debt is non-recourse to Dominion and is secured by Juniper's assets. The annual lease payments made by Dominion to Juniper for Fairless are now eliminated in the Consolidated Statements of Income and are excluded from the lease commitments table in Note 22.

Dominion has not provided any financial or other support to Juniper in the current period that it was not previously contractually required to provide.

XML

Short-Term Debt And Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2012

Short term Debt [Line Items]

Commercial paper bank loans and letters of credit outstanding as well as capacity available under credit facilities

Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:

At December 31,	Facility Limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Capacity Available
(millions)
2012
Joint revolving credit facility(1)	$	3,000	$	2,412		$	—	$	588
Joint revolving credit facility(2)	500		—			26		474
Total	$	3,500	$	2,412	(3)	$	26	$	1,062
2011
Joint revolving credit facility(1)	$	3,000	$	1,814		$	—	$	1,186
Joint revolving credit facility(2)	500		—			36		464
Total	$	3,500	$	1,814	(3)	$	36	$	1,650

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

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

(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion's credit facilities were 0.49% and 0.47% at December 31, 2012 and 2011, respectively.

Virginia Electric and Power Company

Short term Debt [Line Items]

Commercial paper bank loans and letters of credit outstanding as well as capacity available under credit facilities

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:

At December 31,	Facility Sub-limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Sub-Limit Capacity Available
(millions)
2012
Joint revolving credit facility(1)	$	1,000	$	992		$	—	$	8
Joint revolving credit facility(2)	250		—			2		248
Total	$	1,250	$	992	(3)	$	2	$	256
2011
Joint revolving credit facility(1)	$	1,000	$	894		$	—	$	106
Joint revolving credit facility(2)	250		—			15		235
Total	$	1,250	$	894	(3)	$	15	$	341

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

(2) Effective September 2012, the maturity date for $400 million of the $500 million in committed capacity of this credit facility was extended from September 2016 to September 2017. The remaining $100 million continues to have a maturity date of September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power's current sub-limit under this credit facility can be increased or decreased multiple times per year.

(3) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.47% and 0.46% at December 31, 2012 and 2011, respectively.

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value, Option, Quantitative Disclosures

The following table presents Dominion's quantitative information about Level 3 fair value measurements. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility, price correlations, load shaping, and usage factors.

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range		Weighted Average(1)
At December 31, 2012
Assets:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	13	Discounted Cash Flow	Market Price (per Dth)	(3)	(1) - 6		3
Electricity	6		Discounted Cash Flow	Market Price (per MWh)	(3)	30 - 85		50
FTRs	5		Discounted Cash Flow	Market Price (per MWh)	(3)	(6) - 7		1
Capacity	7		Discounted Cash Flow	Market Price (per MW)	(3)	95 - 115		101
Liquids(8)	21		Discounted Cash Flow	Market Price (per Gal)	(3)	0 - 3		1
Physical and Financial Options:
Natural Gas	5		Option Model	Market Price (per Dth)	(3)	3 - 5		4
				Price Volatility	(4)	21% - 36%		24	%
				Price Correlation	(5)	73% - 73%		73	%
Full Requirements Contracts:
Electricity	27		Discounted Cash Flow	Market Price (per MWh)	(3)	8 - 439		40
				Load Shaping	(6)	0% - 10%		5	%
				Usage Factor	(7)	2% - 16%		8	%
Total assets	$	84
Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	18	Discounted Cash Flow	Market Price (per Dth)	(3)	(1) - 18		3
Electricity	1		Discounted Cash Flow	Market Price (per MWh)	(3)	25 - 65		39
FTRs	3		Discounted Cash Flow	Market Price (per MWh)	(3)	(1) - 18		0
Liquids(8)	25		Discounted Cash Flow	Market Price (per Gal)	(3)	1 - 3		2
Physical and Financial Options:
Natural Gas(2)	12		Option Model	Market Price (per Dth)	(3)	3 - 8		5
				Price Volatility	(4)	21% - 36%		32	%
				Price Correlation	(5)	99	%	99	%
Total liabilities	$	59

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

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

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

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

(8) Includes NGLs.

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

Fair Value, Option, Qualitative Disclosures Related to Election

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

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

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

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

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 December 31, 2012
Assets:
Derivatives:
Commodity	$	12	$	639	$	84	$	735
Interest rate	—		93		—		93
Investments(1):
Equity securities:
U.S.:
Large Cap	1,973		—		—		1,973
Other	59		—		—		59
Non-U.S.:
Large Cap	12		—		—		12
Fixed Income:
Corporate debt instruments	—		325		—		325
U.S. Treasury securities and agency debentures	391		152		—		543
State and municipal	—		315		—		315
Other	—		7		—		7
Cash equivalents and other	13		67		—		80
Restricted cash equivalents	—		33		—		33
Total assets	$	2,460	$	1,631	$	84	$	4,175
Liabilities:
Derivatives:
Commodity	$	8	$	528	$	59	$	595
Interest rate	—		66		—		66
Total liabilities	$	8	$	594	$	59	$	661
At December 31, 2011
Assets:
Derivatives:
Commodity	$	44	$	828	$	93	$	965
Interest rate	—		105		—		105
Investments(1):
Equity securities:
U.S.:
Large Cap	1,718		—		—		1,718
Other	51		—		—		51
Non-U.S.:
Large Cap	10		—		—		10
Fixed Income:
Corporate debt instruments	—		332		—		332
U.S. Treasury securities and agency debentures	277		181		—		458
State and municipal	—		329		—		329
Other	—		23		—		23
Cash equivalents and other	—		60		—		60
Restricted cash equivalents	—		141		—		141
Total assets	$	2,100	$	1,999	$	93	$	4,192
Liabilities:
Derivatives:
Commodity	$	10	$	714	$	164	$	888
Interest rate	—		269		—		269
Total liabilities	$	10	$	983	$	164	$	1,157

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

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:

	2012			2011			2010
(millions)
Balance at January 1,	$	(71	)	$	(50	)	$	(66	)
Total realized and unrealized gains (losses):
Included in earnings	(15		)	(77		)	43
Included in other comprehensive income (loss)	101			14			(49		)
Included in regulatory assets/liabilities	30			(42		)	24
Settlements	47			88			(38		)
Transfers out of Level 3	(67		)	(4		)	36
Balance at December 31,	$	25		$	(71	)	$	(50	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$	42		$	22		$	(4	)

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 Energy Purchases			Purchased Gas			Total
(millions)
Year Ended December 31, 2012
Total gains (losses) included in earnings	$	35		$	(50	)	$	—		$	(15	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	42			—			—			42
Year Ended December 31, 2011
Total gains (losses) included in earnings	$	(32	)	$	(45	)	$	—		$	(77	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	22			—			—			22
Year Ended December 31, 2010
Total gains (losses) included in earnings	$	(4	)	$	51		$	(4	)	$	43
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	(4		)	—			—			(4		)

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

For Dominion's and Virginia Power's financial instruments that are not recorded at fair value, the carrying amounts and fair values are as follows:

At December 31,	2012				2011
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	16,841	$	19,898	$	16,264	$	18,936
Long-term debt, including securities due within one year - VIE(3)	860		864		890		892
Junior subordinated notes	1,373		1,430		1,719		1,786
Subsidiary preferred stock(4)	257		255		257		256
Virginia Power
Long-term debt, including securities due within one year(2)	$	6,669	$	8,270	$	6,862	$	8,281
Preferred stock(4)	257		255		257		256

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2) Includes amounts which represent the unamortized discount and premium. At December 31, 2012, and 2011, includes the valuation of certain fair value hedges associated with Dominion's fixed rate debt, of approximately $93 million and $105 million, respectively.

(3) Includes amounts which represent the unamortized premium.

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

Virginia Electric and Power Company

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value, by Balance Sheet Grouping

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 December 31, 2012
Assets:
Derivatives:
Commodity	$	—	$	1	$	5	$	6
Investments(1):
Equity securities:
U.S.:
Large Cap	779		—		—		779
Other	27		—		—		27
Fixed Income:
Corporate debt instruments	—		196		—		196
U.S. Treasury securities and agency debentures	168		66		—		234
State and municipal	—		118		—		118
Other	—		1		—		1
Cash equivalents and other	7		31		—		38
Restricted cash equivalents	—		10		—		10
Total assets	$	981	$	423	$	5	$	1,409
Liabilities:
Derivatives:
Commodity	$	—	$	6	$	3	$	9
Interest rate	—		25		—		25
Total Liabilities	$	—	$	31	$	3	$	34
At December 31, 2011
Assets:
Derivatives:
Commodity	$	—	$	—	$	2	$	2
Investments(1):
Equity securities:
U.S.:
Large Cap	679		—		—		679
Other	23		—		—		23
Fixed Income:
Corporate debt instruments	—		214		—		214
U.S. Treasury securities and agency debentures	107		63		—		170
State and municipal	—		125		—		125
Other	—		16		—		16
Cash equivalents and other	—		40		—		40
Restricted cash equivalents	—		32		—		32
Total assets	$	809	$	490	$	2	$	1,301
Liabilities:
Derivatives:
Commodity	$	—	$	17	$	30	$	47
Interest rate	$	—	$	100	$	—	$	100
Total Liabilities	$	—	$	117	$	30	$	147

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

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

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:

	2012			2011			2010
(millions)
Balance at January 1,	$	(28	)	$	14		$	(10	)
Total realized and unrealized gains (losses):
Included in earnings	(50		)	(45		)	51
Included in regulatory assets/liabilities	30			(42		)	24
Settlements	50			45			(51		)
Transfers out of Level 3	—			—			—
Balance at December 31,	$	2		$	(28	)	$	14

XML

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, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Deferred issuance expenses	$ 2	$ 2
Total gains (losses) included in earnings	(15)	(77)	43
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	42	22	(4)
Operating Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) included in earnings	35	(32)	(4)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	42	22	(4)
Electric Fuel and Energy Purchases
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) included in earnings	(50)	(45)	51
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	0	0	0
Purchased Gas
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) included in earnings	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 still held at the reporting date	$ 0	$ 0	$ 0

XML

Regulatory Matters (Narrative) (Details) (USD $)	12 Months Ended			11 Months Ended	12 Months Ended	1 Months Ended				12 Months Ended	1 Months Ended		12 Months Ended						1 Months Ended	12 Months Ended			1 Months Ended						12 Months Ended				1 Months Ended	12 Months Ended	1 Months Ended		12 Months Ended	1 Months Ended			12 Months Ended	1 Months Ended				12 Months Ended	1 Months Ended																																		12 Months Ended	1 Months Ended	6 Months Ended		1 Months Ended	11 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Nov. 30, 2012 Virginia Regulation	Dec. 31, 2012 Virginia Regulation	Dec. 31, 2012 Virginia Regulation Rider C1 and C2	Dec. 31, 2012 Virginia Regulation Rider R and S	Dec. 31, 2012 Ohio Regulation	Mar. 31, 2012 Ohio Regulation mi	Dec. 31, 2012 Ohio Regulation	May 31, 2012 Virginia Electric and Power Company	Mar. 31, 2010 Virginia Electric and Power Company	Dec. 31, 2012 Virginia Electric and Power Company	Dec. 31, 2011 Virginia Electric and Power Company	Dec. 31, 2010 Virginia Electric and Power Company	Sep. 01, 2008 Virginia Electric and Power Company Project	Jul. 31, 2008 Virginia Electric and Power Company Project	Sep. 30, 2012 Virginia Electric and Power Company Minimum	Jan. 31, 2013 Virginia Electric and Power Company Subsequent Event Minimum	Dec. 31, 2012 Virginia Electric and Power Company Scenario, Forecast	Jul. 31, 2008 Virginia Electric and Power Company 1.5% Percent Incentive Rate For Projects Project	Jul. 31, 2008 Virginia Electric and Power Company 1.25 % Incentive Rate For Projects Project	Dec. 31, 2012 Virginia Electric and Power Company Virginia Regulation	Nov. 30, 2012 Virginia Electric and Power Company Virginia Regulation mi	Jul. 31, 2012 Virginia Electric and Power Company Virginia Regulation	Jun. 30, 2012 Virginia Electric and Power Company Virginia Regulation kV mi	May 31, 2012 Virginia Electric and Power Company Virginia Regulation	Oct. 31, 2011 Virginia Electric and Power Company Virginia Regulation MW	Dec. 31, 2013 Virginia Electric and Power Company Virginia Regulation mi	Dec. 31, 2012 Virginia Electric and Power Company Virginia Regulation mi	Dec. 31, 2011 Virginia Electric and Power Company Virginia Regulation	Dec. 31, 2009 Virginia Electric and Power Company Virginia Regulation	Dec. 31, 2011 Virginia Electric and Power Company Virginia Regulation Base Roe	Dec. 31, 2012 Virginia Electric and Power Company Virginia Regulation Base Roe	Jun. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider R and S	Mar. 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider R and S	Dec. 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider R and S	Jan. 31, 2013 Virginia Electric and Power Company Virginia Regulation Rider R and S April 2013 Subsequent Event	Apr. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider C1A	Apr. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider C2A	Dec. 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider R	Jun. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider R April 2013	Jun. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider R April 2014	Mar. 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider R April 2014	Mar. 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider S	Dec. 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider S	Jun. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider S April 2013	Jun. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider S April 2014	Mar. 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider S Pre Commercial	Mar. 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider S Post Commercial	Aug. 31, 2012 Virginia Electric and Power Company Virginia Regulation Riders C1A And C2A DSM_Program	Aug. 31, 2012 Virginia Electric and Power Company Virginia Regulation Riders C1A And C2A April 2013	Aug. 31, 2012 Virginia Electric and Power Company Virginia Regulation Riders C1A And C2A April 2014	Apr. 30, 2012 Virginia Electric and Power Company Virginia Regulation Riders C1A And C2A Residential Customers DSM_Program	Apr. 30, 2012 Virginia Electric and Power Company Virginia Regulation Riders C1A And C2A Commercial Customers DSM_Program	Apr. 30, 2012 Virginia Electric and Power Company Virginia Regulation Riders C1A And C2A Peak Shaving	Aug. 31, 2012 Virginia Electric and Power Company Virginia Regulation Riders C1A And C2A Air Conditioner Cycling Program	Aug. 31, 2012 Virginia Electric and Power Company Virginia Regulation Riders C1A And C2A Low Income Program	May 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider T	Jul. 31, 2011 Virginia Electric and Power Company Virginia Regulation Rider T	Aug. 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider T1	May 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider T1	May 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider T1 Minimum	May 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider T1 Maximum	Jun. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider W	Feb. 28, 2012 Virginia Electric and Power Company Virginia Regulation Rider W	Jun. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider W April 2013	Jun. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider B	Mar. 31, 2012 Virginia Electric and Power Company Virginia Regulation Rider B MW	Jan. 31, 2013 Virginia Electric and Power Company Virginia Regulation Rider B Subsequent Event	Nov. 30, 2012 Virginia Electric and Power Company Virginia Regulation Rider BW	Aug. 31, 2012 Virginia Electric and Power Company Virginia Regulation Bremo Power Station MW	Dec. 31, 2012 Virginia Electric and Power Company North Carolina Regulation	Sep. 30, 2012 Virginia Electric and Power Company North Carolina Regulation	Aug. 31, 2012 Virginia Electric and Power Company North Carolina Regulation	Mar. 31, 2012 Virginia Electric and Power Company North Carolina Regulation	Dec. 31, 2011 Virginia Electric and Power Company North Carolina Regulation	Dec. 31, 2012 Virginia Electric and Power Company North Carolina Regulation Minimum	Dec. 31, 2012 Virginia Electric and Power Company North Carolina Regulation Maximum	Feb. 28, 2012 East Ohio Ohio Regulation	Dec. 31, 2012 East Ohio Ohio Regulation	Dec. 31, 2012 East Ohio Ohio Regulation Scenario, Forecast	Jun. 30, 2012 East Ohio Ohio Regulation Percentage Of Income Payment Plan Rider	Jun. 30, 2012 East Ohio Ohio Regulation Percentage Of Income Payment Plan Rider Scenario, Forecast	Mar. 31, 2012 East Ohio Ohio Regulation Uncollectible Expense Rider	Feb. 28, 2013 East Ohio Ohio Regulation Uncollectible Expense Rider Scenario, Forecast
Regulatory Matters [Line Items]
Authorized Roe													11.40%																		12.40%	11.40%																																		11.40%
Number of electric transmission projects																11	11				4	7
Incentive for 4 electric transmission enhancement projects													1.50%
Incentive for 7 electric transmission enhancement projects													1.25%
Number of electric transmission projects cancelled																1
Estimated cost of project abandonment													$ 7,000,000
Number of transmission projects approved																10
Estimated cost for electric transmission projects																				852,000,000
Costs claimed to be unjust and excluded from transmission formula rate												223,000,000
Potential settlement required annual payment for 10 years											250,000
Settlement payment duration											10 years
Accrued ancillary services																		33,000,000
Payments for accrued ancillary services																			33,000,000
Basis points representing allowed range of Roe																														0.50%
Roe established in Virginia settlement approval order																														11.90%
Basis points performance incentive for meeting certain RPS targets																																		0.50%
Basis points enhancement to Roe				1.00%																															1.00%	1.00%	1.00%																												1.00%			2.00%	2.00%		1.00%
Roe Virginia Power believes it earned during 2009 and 2010 test years																														13.30%
Percent of earnings above Upper end of Authorized Roe earning band forfeited due to exceeding Roe authorization																														60.00%
Earnings forfeited due to exceeding Roe authorization																														78,000,000
Customer refund credit amortization period	6 months
Actual aggregate expected refund due to exceeding Roe authorization																														81,000,000
Fuel inventory costs included in base rate																															188,000,000
Payout ratio for Aip and Ltip Expenses																														100.00%
Incentive plan costs that exceeded 100 percent payout ratio					21,000,000
Incentive compensation expense																														95,000,000
Reduced operating costs for purposes of earnings test																														103,000,000
Gain on settlement of interest rate hedging Contracts																														44,000,000
Increase (decrease) in Regulatory Liabilities																							50,000,000
Proposed fuel revenue requirement decrease																											389,000,000																																																27,000,000
Revenue requirement under riders																																							5,000,000	17,000,000	78,000,000					199,000,000																				34,000,000
Placeholder return on equity																																					12.30%
New Authorized Roe						10.40%	11.40%																										10.90%	10.90%
Authorized return on equity																																			11.40%	11.40%																													11.40%			12.40%	12.40%		11.40%		10.20%
Proposed revenue requirement																																						248,000,000				81,000,000	75,000,000	74,000,000	226,000,000		249,000,000	229,000,000	52,000,000	174,000,000		4,000,000	23,000,000						473,000,000			373,000,000			86,000,000			12,000,000	6,000,000		45,000,000									47,000,000
Actual revenue requirement																																										78,000,000	72,000,000
Proposed increase decrease revenue requirement																																																													100,000,000		100,000,000	18,000,000			83,000,000
Number of demand side management programs in which extension was requested																																																			2			4	2
Period for demand side management programs																																																						5 years	5 years	5 years	5 years	2 years
Cost recovery cap																																																						90,000,000	45,000,000	14,000,000
Proposed revenue requirement under Rider to go into effect April 1, 2011 for the rate year ending March 31, 2012																																																											481,000,000	466,000,000
Increase in revenue under revenue requirements For Riders																																																											144,000,000
Authorized return on equity enhancement Period																																																																		10 years			5 years		15 years
Rider B renewable generation capacity																																																																					150
Approved revenue requirement																																																																						12,000,000
Capacity preserved from converting units from coal to natural gas																																																																								227
Capacity of facility of company owned solar distribution generation facilities																												30
Capacity of facility of company owned solar distribution generation facilities phase one																												10
Capacity of facility of company owned solar distribution generation facilities phase two																												20
Percentage of energy output purchased																											100.00%
Fixed price of energy output purchased																											0.15
Period to purchase energy output																											5 years
Total cost capitalization																								80,000,000
Virginia Powers portion of Mt Storm to doubs line rebuild																														96
Portion of Dooms to bremo that will replaced																													43
Alternative route for line																										37
KV Line																										500
Length of rebuild line																								39
Period to reopen proceeding																									60 days
North Carolina fuel revenue decrease from proposed settlement																																																																													36,000,000
Fuel factor application annual decrease in fuel expense recovery																																																																													13,000,000
Proposed increase decrease in base revenue																																																																												64,000,000
Proposed non fuel revenue increase																																																																										24,000,000	53,000,000
Approved non-fuel base revenue																																																																									36,000,000
Approved base fuel revenues																																																																									14,000,000
Base revenue approved																																																																									22,000,000
Net regulatory assets																																																																									17,000,000
Net regulatory assets recovery period																																																																														5 years	10 years
Approved non base fuel experience modification factor revenues																																																																									17,000,000
New annual amount of Pir spending per stipulation									200,000,000
Miles of pipeline identified to be replaced									1,450
Current annual Pir capital investment										120,000,000
Proposed annual Pir captial investment										160,000,000
Proposed PIR total gross plant investment																																																																																73,000,000
Cumulative gross plant investment																																																																																362,000,000
Percent of household income that becomes monthly payment										6.00%
Period for elimination of customer arrearage																																																																																	24 months
Refund of overrecovery of accumulated arrearages																																																																																			70,000,000
Period for refund of overrecovery of accumulated arrearages																																																																																			2 years
Recovery of projected deferred program costs																																																																																				104,000,000
Allowance for doubtful accounts receivable, charge-offs																																																																																					1,000,000
Allowance for doubtful accounts receivable, recoveries																																																																																						23,000,000
Amouont of capital expenditures depreciation and property tax can be deferred on								95,000,000
Plant construction and other property additions (including nuclear fuel)	$ 4,145,000,000	$ 3,652,000,000	$ 3,422,000,000										$ 2,082,000,000	$ 1,885,000,000	$ 2,113,000,000																																																																			$ 93,000,000

XML

Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Operating Revenue

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. The Companies collect sales, consumption and consumer utility taxes; however, these amounts are excluded from revenue. Dominion's customer receivables at December 31, 2012 and 2011 included $411 million and $423 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power's customer receivables at December 31, 2012 and 2011 included $348 million and $360 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers.

The primary types of sales and service activities reported as operating revenue for Dominion are as follows:

• Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;

• Regulated gas sales consist primarily of state-regulated retail natural gas sales and related distribution services;

• Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties;

• Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services and associated derivative activity. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; and

• Other revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes miscellaneous service revenue from electric and gas distribution operations, and gas processing and handling revenue.

The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:

• Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and

• Other revenue consists primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.

Electric Fuel Purchased Energy and Purchased Gas-Deferred Costs

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Where permitted by regulatory authorities, the differences between Virginia Power's actual electric fuel and purchased energy expenses and Dominion's purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.

Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 83% is currently subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.

Income Taxes

Income Taxes

A consolidated federal income tax return is filed for Dominion and its subsidiaries, including Virginia Power. In addition, where applicable, combined income tax returns for Dominion and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed. Virginia Power participates in an intercompany tax sharing agreement with Dominion and its subsidiaries, and its current income taxes are based on its taxable income or loss, determined on a separate company basis.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

Dominion and Virginia Power recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the consolidated balance sheets and current payables are included in accrued interest, payroll and taxes on the consolidated balance sheets, except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities.

Dominion and Virginia Power recognize changes in estimated interest payable on net underpayments of income taxes in interest expense. Changes in interest receivable related to net overpayments of income taxes and estimated penalties that may result from the settlement of some uncertain tax positions are recognized in other income. In its Consolidated Statements of Income for 2012, Dominion recognized interest income of $8 million and interest expense of $3 million and a reduction in penalties of less than $1 million. In 2011, Dominion recognized interest income of $12 million and interest expense of $7 million and a reduction in penalties of less than $1 million. In 2010, Dominion recognized a reduction in interest expense of $18 million and a reduction in penalties of less than $1 million. Dominion had accrued interest receivable of $5 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2012 and interest receivable of $48 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2011.

Virginia Power's interest and penalties were immaterial in 2012 and 2010. In 2011, Virginia Power recognized interest income of $12 million, and penalties were immaterial. Virginia Power had accrued interest receivable of $17 million at December 31, 2011.

At December 31, 2012, Virginia Power's Consolidated Balance Sheet included $10 million of federal income taxes payable and $36 million of noncurrent federal and state income taxes payable.

At December 31, 2011, Virginia Power's Consolidated Balance Sheet included $18 million of current federal income taxes receivable, $34 million of current state income taxes payable and $110 million of noncurrent federal and state income taxes payable.

Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Cash and Cash Equivalents

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 2012 and 2011, Dominion's accounts payable included $53 million and $75 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 2012 and 2011, Virginia Power's accounts payable included $30 million and $40 million, respectively, of checks outstanding but not yet presented for payment. For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Derivative Instruments

Derivative Instruments

Dominion and Virginia Power use derivative instruments such as futures, swaps, forwards, options and FTRs to manage the commodity, currency exchange and financial market risks of their business operations.

All derivatives, other than those for which an exception applies, are reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.

Dominion and Virginia Power do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion had margin assets of $212 million and $319 million associated with cash collateral at December 31, 2012 and 2011, respectively. Dominion had margin liabilities of $4 million and $66 million associated with cash collateral at December 31, 2012 and 2011, respectively. Virginia Power had margin assets of $18 million and $41 million associated with cash collateral at December 31, 2012 and 2011, respectively. Virginia Power's margin liabilities associated with cash collateral were not material at December 31, 2012 and 2011.

To manage price risk, Dominion and Virginia Power hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. As part of Dominion's strategy to market energy and manage related risks, it also manages a portfolio of commodity-based financial derivative instruments held for trading purposes. Dominion uses established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and uses various derivative instruments to reduce risk by creating offsetting market positions.

Statement of Income Presentation:

• Derivatives Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis.

• Derivatives Not Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses or interest and related charges based on the nature of the underlying risk.

In Virginia Power's generation operations, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.

DERIVATIVE INSTRUMENTS DESIGNATEDAS HEDGING INSTRUMENTS

Dominion and Virginia Power designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, Dominion and Virginia Power formally document the relationship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using the hedging instrument. The Companies assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges-A majority of Dominion's and Virginia Power's hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and other energy-related products. The Companies also use foreign currency contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which Dominion and Virginia Power are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Fair Value Hedges-Dominion also uses fair value hedges to mitigate the fixed price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, Dominion and Virginia Power have designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item's fair value. Derivative gains and losses from the hedged item are reclassified to earnings when the hedged item is included in earnings, or earlier, if the hedged item no longer qualifies for hedge accounting. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting.

See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment, including additions and replacements is recorded at original cost, consisting of labor and materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as it is incurred.

In 2012, 2011 and 2010, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $91 million, $85 million and $102 million, respectively. In 2012, 2011 and 2010, Virginia Power capitalized AFUDC to property, plant and equipment of $31 million, $31 million and $61 million, respectively. Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2012, 2011 and 2010, Virginia Power recorded $37 million, $20 million and $13 million of AFUDC related to these projects, respectively.

For Virginia Power property subject to cost-of-service rate regulation, including electric distribution, electric transmission, and generation property and for certain Dominion natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be retired or abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be retired or abandoned.

For Dominion and Virginia Power property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property's net book value at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. Dominion's and Virginia Power's depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2012	2011	2010
(percent)
Dominion
Generation	2.62	2.68	2.59
Transmission	2.17	2.26	2.24
Distribution	3.17	3.19	3.20
Storage	2.59	2.64	2.75
Gas gathering and processing	2.49	2.52	2.39
General and other	4.55	4.66	4.60
Virginia Power
Generation	2.62	2.68	2.59
Transmission	1.98	2.03	1.94
Distribution	3.32	3.33	3.33
General and other	4.32	4.38	4.28

Dominion's nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

Asset	Estimated Useful Lives
Merchant generation-nuclear	34-44 years
Merchant generation-other	27-40 years
General and other	5-59 years

Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.

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, Dominion no longer has any significant gas and oil properties subject to the ceiling test calculation.

In 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 and recognized a gain from the sale of substantially all of its Appalachian E&P operations, as discussed in Note 3.

Emissions Allowances

Emissions Allowances

Emissions allowances permit the holder of the allowance to emit certain gaseous by-products of fossil fuel combustion, including SO₂, NO_X and CO₂. SO₂ and NO_X emissions allowances are issued to Dominion and Virginia Power by the EPA and may also be purchased and sold via third party contracts. CO₂ emissions allowances are available for purchase by Dominion through quarterly auctions held by participating RGGI states. Compliance with the RGGI requirements only applies to certain of Dominion's merchant power stations located in the Northeast.

Allowances held may be transacted with third parties or consumed as these emissions are generated. Allowances allocated to or acquired by the Companies' generation operations are held primarily for consumption.

Allowances held for consumption are classified as intangible assets in the Consolidated Balance Sheets. Carrying amounts are based on the cost to acquire the allowances or, in the case of a business combination, on the fair values assigned to them in the allocation of the purchase price of the acquired business. A portion of Dominion's and Virginia Power's SO₂ and NO_X allowances are issued by the EPA at zero cost.

These allowances are amortized in the periods the emissions are generated, with the amortization reflected in depreciation, depletion and amortization in the Consolidated Statements of Income. Purchases and sales of these allowances are reported as investing activities in the Consolidated Statements of Cash Flows and gains or losses resulting from sales are reported in other operations and maintenance expense in the Consolidated Statements of Income. See Note 6 for discussion of impairments related to emissions allowances.

Long-Lived and Intangible Assets

Long-Lived and Intangible Assets

Dominion and Virginia Power perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for a discussion of impairments related to certain long-lived assets and intangible assets with finite lives.

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

The accounting for Dominion's regulated gas and Virginia Power's regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made.

Asset Retirement Obligations

Asset Retirement Obligations

Dominion and Virginia Power recognize AROs at fair value as incurred or when sufficient information becomes available to

determine a reasonable estimate of the fair value of future retirement activities to be performed. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Dominion reports accretion of AROs associated with its natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Virginia Power reports accretion of AROs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Accretion of all other AROs is reported in other operations and maintenance expense in the Consolidated Statements of Income.

Amortization of Debt Issuance Costs

Amortization of Debt Issuance Costs

Dominion and Virginia Power defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized over the lives of the new issuances.

Investments

Investments

MARKETABLE EQUITYAND DEBT SECURITIES

Dominion accounts for and classifies investments in marketable equity and debt securities as trading or available-for-sale securities. Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities.

• Trading securities include marketable equity and debt securities held by Dominion in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

• Available-for-sale securities include all other marketable equity and debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power's nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other available-for-sale securities, including those held in Dominion's merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

In determining realized gains and losses for marketable equity and debt securities, the cost basis of the security is based on the specific identification method.

NON-MARKETABLE INVESTMENTS

Dominion and Virginia Power account for illiquid and privately held securities for which market prices or quotations are not readily available under either the equity or cost method. Non-marketable investments include:

• Equity method investments when Dominion and Virginia Power have the ability to exercise significant influence, but not control, over the investee. Dominion's investments are included in investments in equity method affiliates and Virginia Power's investments are included in other investments in their Consolidated Balance Sheets. Dominion and Virginia Power record equity method adjustments in other income in the Consolidated Statements of Income including: their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

• Cost method investments when Dominion and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion's and Virginia Power's investments are included in other investments and nuclear decommissioning trust funds.

OTHER-THAN-TEMPORARY IMPAIRMENT

Dominion and Virginia Power periodically review their investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period.

Decommissioning Trust Investments-Special Considerations

• The recognition provisions of the FASB's other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities.

• Debt Securities- Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, the Companies record the credit loss in earnings and any remaining portion of the unrealized loss in other comprehensive income. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

• Equity securities and other investments- Dominion's and Virginia Power's method of assessing other-than-temporary declines requires demonstrating the ability to hold individual securities for a period of time sufficient to allow for the anticipated recovery in their market value prior to the consideration of the other criteria mentioned above. Since the Companies have limited ability to oversee the day-to-day management of nuclear decommissioning trust fund investments, they do not have the ability to ensure investments are held through an anticipated recovery period. Accordingly, they consider all equity and other securities as well as non-marketable investments held in nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired.

Inventories

Inventories

Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory used in East Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at $24 million and $48 million at December 31, 2012 and December 31, 2011, respectively. Based on the average price of gas purchased during 2012 and 2011, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $69 million and $86 million, respectively. Stored gas inventory held by Hope and certain nonregulated gas operations is valued using the weighted-average cost method.

Gas Imbalances

Gas Imbalances

Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion values these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion from other parties are reported in other current assets and imbalances that Dominion owes to other parties are reported in other current liabilities in the Consolidated Balance Sheets.

Goodwill

Goodwill

Dominion evaluates goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.

XML

Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2012

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Schedule Of Preferred Stock

Presented below are the series of Virginia Power preferred stock that were outstanding as of December 31, 2012:

Dividend	Issued and Outstanding Shares	Entitled Per  Share Upon Liquidation
	(thousands)
$5.00	107	$	112.50
4.04	13	102.27
4.20	15	102.50
4.12	32	103.73
4.80	73	101.00
7.05	500	100.36		(1)
6.98	600	100.35		(2)
Flex Money Market Preferred 12/02, Series A	1,250	100.00		(3)
Total	2,590

(1) Through 7/31/2013; $100.00 commencing 8/1/2013.

(2) Through 8/31/2013; $100.00 commencing 9/1/2013.

(3) Dividend rate was 6.25% until 3/20/2011. Effective 3/20/11 the rate reset to 6.12% until 3/20/2014 after which the rate will be determined according to periodic auctions for periods established by Virginia Power at the time of the auction process

XML

Income Taxes (The Companies Deferred Income Taxes Components) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Income Tax Contingency [Line Items]
Total deferred income tax assets	$ 2,505	$ 2,229
Total deferred income tax liabilities	7,716	7,424
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	4,601	4,008
Nuclear decommissioning	994	913
Deferred state income taxes	474	493
Federal benefit of deferred state income taxes	(166)	(173)
Deferred fuel, purchased energy and gas costs	3	161
Pension benefits	231	396
Other postretirement benefits	(171)	(167)
Loss and credit carryforwards	(656)	(577)
Reserve for rate proceedings	0	(54)
Partnership basis differences	174	274
Valuation allowances	93	96
Other	(366)	(175)
Total net deferred income tax liabilities	5,211	5,195
Virginia Electric and Power Company
Income Tax Contingency [Line Items]
Total deferred income tax assets	466	503
Total deferred income tax liabilities	4,238	3,759
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	3,394	2,758
Nuclear decommissioning	407	374
Deferred state income taxes	265	243
Federal benefit of deferred state income taxes	(93)	(85)
Deferred fuel, purchased energy and gas costs	(16)	144
Pension benefits	(17)	8
Other postretirement benefits	(7)	(13)
Loss and credit carryforwards	(77)	(55)
Reserve for rate proceedings	0	(54)
Partnership basis differences	0	0
Valuation allowances	0	0
Other	(84)	(64)
Total net deferred income tax liabilities	$ 3,772	$ 3,256

XML

Shareholders' Equity (Summary of Restricted Stock and Goal-Based Stock Activity) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Nonvested beginning, Shares	1,301	1,476	1,484
Granted, Shares	390	299	463
Vested, Shares	(596)	(617)	(618)
Cancelled and forfeited, Shares	(10)	(25)	(39)
Converted from goal-based stock to restricted stock, Shares		(168)	(186)
Nonvested ending, Shares	1,085	1,301	1,476
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Nonvested beginning, Weighted Average Grant Date Fair Value	$ 37.37	$ 38.20	$ 39.88
Granted, Weighted Average Grant Date Fair Value	$ 51.14	$ 43.68	$ 38.80
Vested, Weighted Average Grant Date Fair Value	$ 33.31	$ 40.72	$ 43.54
Cancelled and forfeited, Weighted Average Grant Date Fair Value	$ 42.99	$ 36.29	$ 36.92
Converted from goal-based stock to restricted stock, Weighted Average Grant Date Fair Value		$ 30.99	$ 40.84
Nonvested ending, Weighted Average Grant Date Fair Value	$ 44.46	$ 37.37	$ 38.20
Goal-Based Stock
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Nonvested beginning, Shares	12	161	323
Granted, Shares	1	3	9
Vested, Shares	(9)	(20)	(16)
Cancelled and forfeited, Shares			(8)
Converted from goal-based stock to restricted stock, Shares	(2)	(132)	(147)
Nonvested ending, Shares	4	12	161
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Nonvested beginning, Weighted Average Grant Date Fair Value	$ 39.19	$ 31.79	$ 36.12
Granted, Weighted Average Grant Date Fair Value	$ 52.48	$ 43.54	$ 37.46
Vested, Weighted Average Grant Date Fair Value	$ 37.46	$ 34.62	$ 39.31
Cancelled and forfeited, Weighted Average Grant Date Fair Value			$ 30.99
Converted from goal-based stock to restricted stock, Weighted Average Grant Date Fair Value		$ 30.99	$ 40.84
Nonvested ending, Weighted Average Grant Date Fair Value	$ 45.60	$ 39.19	$ 31.79

XML

Dispositions (Narrative) (Details) (USD $)	12 Months Ended	1 Months Ended	3 Months Ended	1 Months Ended	12 Months Ended	1 Months Ended
	Dec. 31, 2012	Apr. 30, 2010 Appalachian E & P acre	Jun. 30, 2010 Appalachian E & P	Feb. 28, 2010 Peoples	Dec. 31, 2010 Peoples	Mar. 31, 2010 Operating Revenue Appalachian E & P
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
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
Write-off of goodwill	11,000,000		134,000,000	79,000,000
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

XML

Goodwill And Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Segment allocation of goodwill

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

	Dominion Generation		Dominion Energy			DVP		Corporate and Other		Total
(millions)
Balance at December 31, 2010(1)	$	1,338	$	712		$	1,091	$	—	$	3,141
Impairments/adjustments	—		—			—		—		—
Balance at December 31, 2011(1)	$	1,338	$	712		$	1,091	$	—	$	3,141
Asset disposition adjustment	—		(11		)	—		—		(11		)
Balance at December 31, 2012(1)	$	1,338	$	701		$	1,091	$	—	$	3,130

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

Components of intangible assets

The components of intangible assets are as follows:

At December 31,	2012				2011
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion
Software, licenses and other	$	859	$	327	$	888	$	278
Emissions allowances	5		1		80		53
Total	$	864	$	328	$	968	$	331
Virginia Power
Software, licenses and other	$	303	$	122	$	285	$	102
Total	$	303	$	122	$	285	$	102

Annual amortization expense of intangible assets

Annual amortization expense for these intangible assets is estimated to be as follows:

	2013		2014		2015		2016		2017
(millions)
Dominion	$	65	$	56	$	43	$	37	$	25
Virginia Power	$	20	$	18	$	12	$	8	$	5

XML

Consolidated Statements of Equity (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Preferred dividends related to noncontrolling interest	$ 16	$ 17	$ 17

XML

Employee Benefit Plans (Benefit Payments Expected Future Service) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2013	$ 231
2014	245
2015	255
2016	300
2017	334
2018-2022	1,749
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
2013	89
2014	93
2015	96
2016	100
2017	103
2018-2022	$ 555

XML

Dispositions (Schedule of Disposal Groups, Including Discontinued Operations, Income Statement) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment charge	$ 2,100
State Line and Salem Harbor
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenue	57		233		269
Loss before income taxes	(49)	[1]	(34)	[1]	(158)	[1]
Impairment charge			55		194
Peoples
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenue					67
Loss before income taxes					$ (134)	[2]

[1] Includes long-lived asset impairment charges of $55 million and $194 million in 2011 and 2010, respectively.

[2] Includes a loss and other charges related to the sale of Peoples.

XML

Commitments and Contingencies (Nuclear Operations) (Narrative) (Details) (USD $)	12 Months Ended			1 Months Ended		3 Months Ended			12 Months Ended				1 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 Spent Nuclear Fuel	Dec. 31, 2011 Spent Nuclear Fuel	Sep. 30, 2012 Millstone	Sep. 30, 2012 Kewaunee	Dec. 31, 2012 Kewaunee Minimum	Dec. 31, 2012 Kewaunee Maximum	Feb. 01, 2013 Kewaunee Subsequent Event	Dec. 31, 2012 Nuclear Plant	Dec. 31, 2012 Virginia Electric and Power Company	Dec. 31, 2012 Virginia Electric and Power Company Spent Nuclear Fuel	Dec. 31, 2011 Virginia Electric and Power Company Spent Nuclear Fuel	Nov. 30, 2012 Virginia Electric and Power Company Surry and North Anna
Loss Contingencies [Line Items]
Minimum financial assurance	$ 3,300,000,000									$ 1,800,000,000
Liability protection under Price-Anderson Act									12,600,000,000
Amount of coverage purchased from commercial insurance pools	375,000,000
Amount that could be assessed for each licensed reactor	118,000,000
Amount that could be assessed for each licensed reactor per reactor	18,000,000
Coverage that exceeds NRC minimum requirement	1,060,000,000
Maximum assessment for premiums on insurance policy	89,000,000									48,000,000
Maximum assessment for insurance policy	33,000,000					33,000,000	30,000,000			20,000,000
Property insurance coverage								1,800,000,000
Payments for legal settlements				20,000,000	6,000,000								75,000,000
Receviables for spent nuclear fuel related costs		$ 36,000,000	$ 102,000,000								$ 26,000,000	$ 76,000,000

XML

Operating Segment (Schedule of Segment Reporting Information, by Segment) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended												12 Months Ended
	Dec. 31, 2012		Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012		Dec. 31, 2011		Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Segment Reporting Information [Line Items]
Total revenue from external customers	$ 3,167		$ 3,411	$ 3,053	$ 3,462	[1]	$ 3,129		$ 3,745	$ 3,288	$ 3,983	[1]	$ 13,093		$ 14,145	[2]	$ 14,927	[2]
Intersegment revenue													0		0		0
Total operating revenue													13,093		14,145		14,927
Depreciation, depletion and amortization													1,186		1,066		1,035
Equity in earnings of equity method investees													25		35		42
Interest income													61		67		71
Interest and related charges													882		867		826
Income taxes													146	[3]	754	[2],[3]	2,112	[2],[3]
Income (loss) from discontinued operations, net of tax													(22)	[4]	(25)	[2],[4]	(258)	[2],[4]
Net income attributable to Dominion	(659)		209	258	494	[1]	201		392	336	479	[1]	302		1,408	[2]	2,808	[2]
Investment in equity method affiliates	558						553						558		553
Capital expenditures													4,145		3,652		3,422
Total assets	46,838						45,614						46,838		45,614
DVP
Segment Reporting Information [Line Items]
Total revenue from external customers													3,385		3,663		3,613
Intersegment revenue													112		173		207
Total operating revenue													3,497		3,836		3,820
Depreciation, depletion and amortization													402		374		353
Equity in earnings of equity method investees													0		0		0
Interest income													9		22		12
Interest and related charges													187		185		158
Income taxes													351		318		277
Income (loss) from discontinued operations, net of tax													0		0		0
Net income attributable to Dominion													559		501		448
Investment in equity method affiliates	1						8						1		8
Capital expenditures													1,158		1,091		1,038
Total assets	12,100						11,500						12,100		11,500
Dominion Generation
Segment Reporting Information [Line Items]
Total revenue from external customers													6,517	[5]	7,080	[5]	7,735	[5]
Intersegment revenue													333	[5]	355	[5]	413	[5]
Total operating revenue													6,850	[5]	7,435	[5]	8,148	[5]
Depreciation, depletion and amortization													500	[5]	457	[5]	443	[5]
Equity in earnings of equity method investees													3	[5]	3	[5]	11	[5]
Interest income													57	[5]	54	[5]	45	[5]
Interest and related charges													208	[5]	217	[5]	179	[5]
Income taxes													479	[5]	583	[5]	756	[5]
Income (loss) from discontinued operations, net of tax													0	[5]	0	[5]	0	[5]
Net income attributable to Dominion													874	[5]	968	[5]	1,263	[5]
Investment in equity method affiliates	414	[5]					415	[5]					414	[5]	415	[5]
Capital expenditures													1,615	[5]	1,593	[5]	1,742	[5]
Total assets	21,200	[5]					22,100	[5]					21,200	[5]	22,100	[5]
Dominion Energy
Segment Reporting Information [Line Items]
Total revenue from external customers													1,813		2,044		2,335
Intersegment revenue													930		1,077		1,166
Total operating revenue													2,743		3,121		3,501
Depreciation, depletion and amortization													216		207		210
Equity in earnings of equity method investees													23		23		21
Interest income													30		27		12
Interest and related charges													47		57		85
Income taxes													352		323		302
Income (loss) from discontinued operations, net of tax													0		0		0
Net income attributable to Dominion													551		521		475
Investment in equity method affiliates	141						104						141		104
Capital expenditures													1,350		907		613
Total assets	11,200						10,600						11,200		10,600
Corporate and Other
Segment Reporting Information [Line Items]
Total revenue from external customers													307	[5]	55	[5]	19	[5]
Intersegment revenue													608	[5]	596	[5]	750	[5]
Total operating revenue													915	[5]	651	[5]	769	[5]
Depreciation, depletion and amortization													68	[5]	28	[5]	29	[5]
Equity in earnings of equity method investees													(1)	[5]	9	[5]	10	[5]
Interest income													71	[5]	70	[5]	92	[5]
Interest and related charges													546	[5]	514	[5]	494	[5]
Income taxes													(1,036)	[5]	(470)	[5]	777	[5]
Income (loss) from discontinued operations, net of tax													(22)	[5]	(25)	[5]	(258)	[5]
Net income attributable to Dominion													(1,682)	[5]	(582)	[5]	622	[5]
Investment in equity method affiliates	2	[5]					26	[5]					2	[5]	26	[5]
Capital expenditures													22	[5]	61	[5]	29	[5]
Total assets	12,600	[5]					11,400	[5]					12,600	[5]	11,400	[5]
Adjustments & Eliminations
Segment Reporting Information [Line Items]
Total revenue from external customers													1,071		1,303		1,225
Intersegment revenue													(1,983)		(2,201)		(2,536)
Total operating revenue													(912)		(898)		(1,311)
Depreciation, depletion and amortization													0		0		0
Equity in earnings of equity method investees													0		0		0
Interest income													(106)		(106)		(90)
Interest and related charges													(106)		(106)		(90)
Income taxes													0		0		0
Income (loss) from discontinued operations, net of tax													0		0		0
Net income attributable to Dominion													0		0		0
Investment in equity method affiliates	0						0						0		0
Capital expenditures													0		0		0
Total assets	(10,300)						(10,000)						(10,300)		(10,000)
Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Total revenue from external customers	1,630		2,086	1,756	1,754		1,555		2,177	1,757	1,757		7,226		7,246		7,219
Total operating revenue													7,226		7,246		7,219
Depreciation, depletion and amortization													782		718		671
Interest income													8		18		15
Interest and related charges													385		331		347
Income taxes													653	[6]	540	[6]	542	[6]
Net income attributable to Dominion	220		415	172	243		6		297	241	278		1,050		822		852
Capital expenditures													2,288		2,090		2,234
Total assets	24,811						23,544						24,811		23,544
Virginia Electric and Power Company | DVP
Segment Reporting Information [Line Items]
Total operating revenue													1,847		1,793		1,680
Depreciation, depletion and amortization													392		368		344
Interest income													1		10		11
Interest and related charges													186		182		158
Income taxes													277		265		228
Net income attributable to Dominion													448		426		377
Capital expenditures													1,142		1,081		1,035
Total assets	11,400						10,700						11,400		10,700
Virginia Electric and Power Company | Dominion Generation
Segment Reporting Information [Line Items]
Total operating revenue													5,379		5,546		5,546
Depreciation, depletion and amortization													390		350		327
Interest income													7		8		4
Interest and related charges													199		199		189
Income taxes													403		447		385
Net income attributable to Dominion													653		664		630
Capital expenditures													1,146		1,009		1,199
Total assets	14,800						14,300						14,800		14,300
Virginia Electric and Power Company | Corporate and Other
Segment Reporting Information [Line Items]
Total operating revenue													0		(93)		(7)
Depreciation, depletion and amortization													0		0		0
Interest income													0		0		0
Interest and related charges													0		(50)		0
Income taxes													(27)		(172)		(71)
Net income attributable to Dominion													(51)		(268)		(155)
Capital expenditures													0		0		0
Total assets	0						0						0		0
Virginia Electric and Power Company | Adjustments & Eliminations
Segment Reporting Information [Line Items]
Total operating revenue													0		0		0
Depreciation, depletion and amortization													0		0		0
Interest income													0		0		0
Interest and related charges													0		0		0
Income taxes													0		0		0
Net income attributable to Dominion													0		0		0
Capital expenditures													0		0		0
Total assets	$ (1,400)						$ (1,500)						$ (1,400)		$ (1,500)

[1] Revenue and income amounts have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

[2] Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

[3] In 2012, Dominion's current federal income tax benefit includes a benefit related to the carryback of its current year operating loss, and deferred state income tax benefit reflects the impact of Brayton Point, Kincaid and Kewaunee impairment charges. In 2011, Dominion's federal income tax expense includes a benefit related to its current year operating loss that is expected to be used in future years, and state income tax expense reflects changes in the amount of income apportioned among states, higher tax credits, claims for refunds and previously unrecognized tax benefits due to the expiration of statutes of limitations.

[4] Includes income tax benefit of $27 million, $9 million, and $34 million in 2012, 2011 and 2010, respectively.

[5] Segment information has been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

[6] In 2011, Virginia Power's federal income tax expense includes a benefit related to a portion of its current year operating loss that is expected to be used in future years. Also, in 2011 and 2010, Virginia Power's federal income tax expense reflects the amounts of current year operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

XML

Derivatives and Hedge Accounting Activities (Tables)

12 Months Ended

Dec. 31, 2012

Derivative [Line Items]

Volumes of Derivatives

The following table presents the volume of Dominion's derivative activity as of December 31, 2012. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)	249		68
Basis(1)	786		534
Electricity (MWh):
Fixed price(1)	20,100,938		12,582,674
FTRs	46,851,683		—
Capacity (MW)	151,025		148,461
Liquids (gallons)(2)	164,682,000		145,698,000
Interest rate	$	1,500,000,000	$	2,250,000,000

(1) Includes options.

(2) Includes NGLs and oil.

Cash Flow Hedges Included Accumulated Other Comprehensive Income (Loss)

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion's Consolidated Balance Sheet at December 31, 2012:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(28	)	$	(24	)	27 months
Electricity	68			17			36 months
Other	3			2			41 months
Interest rate	(165		)	(21		)	361 months
Total	$	(122	)	$	(26	)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The following tables present the fair values of Dominion's derivatives and where they are presented in its Consolidated Balance Sheets:

At December 31, 2012	Fair Value  - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
ASSETS
Current Assets
Commodity	$	103	$	379	$	482
Interest rate	36		—		36
Total current derivative assets	139		379		518
Noncurrent Assets
Commodity	130		123		253
Interest rate	57		—		57
Total noncurrent derivative assets(1)	187		123		310
Total derivative assets	$	326	$	502	$	828
LIABILITIES
Current Liabilities
Commodity	$	103	$	341	$	444
Interest rate	66		—		66
Total current derivative liabilities	169		341		510
Noncurrent Liabilities
Commodity	58		93		151
Total noncurrent derivative liabilities(2)	58		93		151
Total derivative liabilities	$	227	$	434	$	661
At December 31, 2011
ASSETS
Current Assets
Commodity	$	176	$	495	$	671
Interest rate	34		—		34
Total current derivative assets	210		495		705
Noncurrent Assets
Commodity	198		96		294
Interest rate	71		—		71
Total noncurrent derivative assets(1)	269		96		365
Total derivative assets	$	479	$	591	$	1,070
LIABILITIES
Current Liabilities
Commodity	$	162	$	530	$	692
Interest rate	222		37		259
Total current derivative liabilities	384		567		951
Noncurrent Liabilities
Commodity	118		78		196
Interest rate	—		10		10
Total noncurrent derivative liabilities(2)	118		88		206
Total derivative liabilities	$	502	$	655	$	1,157

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

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

Derivative Instruments Gain (Loss) by Hedging Relationship by Income Statement Location

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 Year Ended December 31, 2012	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)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	188
Purchased gas				(75		)
Electric fuel and other energy-related purchases				(17		)
Total commodity	$	71		$	96		$	10
Interest rate(3)	(84		)	(2		)	(35		)
Total	$	(13	)	$	94		$	(25	)
Year Ended December 31, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	153
Purchased gas				(78		)
Electric fuel and other energy-related purchases				(2		)
Purchased electric capacity				1
Total commodity	$	137		$	74		$	(20	)
Interest rate(3)	(252		)	(8		)	(143		)
Total	$	(115	)	$	66		$	(163	)
Year Ended December 31, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	557
Purchased gas				(155		)
Electric fuel and other energy-related purchases				(8		)
Purchased electric capacity				3
Total commodity	$	139		$	397		$	(17	)
Interest rate(3)	(3		)	109			(27		)
Foreign currency(4)	—			1			(2		)
Total	$	136		$	507		$	(46	)

(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

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2012			2011			2010
(millions)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue	$	168		$	111		$	67
Purchased gas	(14		)	(35		)	(41		)
Electric fuel and other energy-related purchases	(40		)	(45		)	51
Interest rate(2)	17			(5		)	(37		)
Total	$	131		$	26		$	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 Electric and Power Company

Derivative [Line Items]

Volumes of Derivatives

The following table presents the volume of Virginia Power's derivative activity at December 31, 2012. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price	16		—
Basis	8		—
Electricity (MWh):
Fixed price	709,600		—
FTRs	43,570,739		—
Capacity (MW)	107,000		93,800
Interest rate	$	500,000,000	$	250,000,000

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The following tables present the fair values of Virginia Power's derivatives and where they are presented in its Consolidated Balance Sheets:

At December 31, 2012	Fair Value  - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
ASSETS
Current Assets
Commodity	$	1	$	5	$	6
Total current derivative assets(1)	1		5		6
Total derivative assets	$	1	$	5	$	6
LIABILITIES
Current Liabilities
Commodity	$	5	$	3	$	8
Interest rate	25		—		25
Total current derivative liabilities	30		3		33
Noncurrent Liabilities
Commodity	1		—		1
Total noncurrent derivative liabilities(2)	1		—		1
Total derivative liabilities	$	31	$	3	$	34
At December 31, 2011
ASSETS
Current Assets
Commodity	$	—	$	2	$	2
Total current derivative assets(1)	—		2		2
Total derivative assets	$	—	$	2	$	2
LIABILITIES
Current Liabilities
Commodity	$	14	$	31	$	45
Interest rate	$	53	$	37	$	90
Total current derivative liabilities	67		68		135
Noncurrent Liabilities
Commodity	2		—		2
Interest rate	—		10		10
Total noncurrent derivative liabilities(2)	2		10		12
Total derivative liabilities	$	69	$	78	$	147

(1) Current derivative assets are presented in other current assets in Virginia Power's Consolidated Balance Sheets.

(2) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power's Consolidated Balance Sheets.

Derivative Instruments Gain (Loss) by Hedging Relationship by Income Statement Location

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 Year Ended December 31, 2012	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)
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(4	)
Total commodity	$	(2	)	$	(4	)	$	10
Interest rate(3)	(6		)	—			(35		)
Total	$	(8	)	$	(4	)	$	(25	)
Year Ended December 31, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Purchased electric capacity				1
Total commodity	$	(3	)	$	—		$	(20	)
Interest rate(3)	(6		)	1			(143		)
Total	$	(9	)	$	1		$	(163	)
Year Ended December 31, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Purchased electric capacity				4
Total commodity	$	(1	)	$	3		$	(17	)
Interest rate(3)	(1		)	9			(27		)
Foreign currency(4)	—			—			(2		)
Total	$	(2	)	$	12		$	(46	)

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

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

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

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

Schedule Of Derivatives Not Designated As Hedging Instruments

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2012			2011			2010
(millions)
Derivative Type and Location of Gains (Losses)
Commodity(2)	$	(50	)	$	(45	)	$	51
Interest rate(3)	—			(5		)	(3		)
Total	$	(50	)	$	(50	)	$	48

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

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

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

XML

Shareholders' Equity

12 Months Ended

Dec. 31, 2012

Stockholders' Equity Note [Abstract]

Shareholders' Equity

SHAREHOLDERS' EQUITY

Issuance of Common Stock

DOMINION

Dominion maintains Dominion Direct^® and a number of employee savings plans through which contributions may be invested in Dominion's common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2012, Dominion began issuing new common shares for these direct stock purchase plans.

During 2012, Dominion issued approximately 6.4 million shares of common stock through various programs.  Dominion received cash proceeds of $265 million from the issuance of 5.3 million of such shares through Dominion Direct, employee savings plans, and the exercise of employee stock options.

In January 2012, Dominion filed a new SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at the market program.  Dominion entered into four separate Sales Agency Agreements to effect sales under the program.  However, with the exception of issuing approximately $318 million in equity through employee savings plans, direct stock purchase and dividend reinvestment plans, converted securities and other employee and director benefit plans, Dominion did not issue common stock in 2012. 

VIRGINIA POWER

In 2012 and 2011, Virginia Power did not issue any shares of its common stock to Dominion. In 2010, Virginia Power issued 33,013 shares of its common stock to Dominion for approximately $1 billion, for the purpose of retiring short-term demand note borrowings from Dominion.

Shares Reserved for Issuance

At December 31, 2012, Dominion had approximately 48 million shares reserved and available for issuance for Dominion Direct^®, employee stock awards, employee savings plans, director stock compensation plans and contingent convertible senior notes.

Repurchase of Common Stock

During 2011, Dominion repurchased approximately 13 million shares of common stock for approximately $601 million on the open market, at an average price of $46.37 per share. Dominion did not repurchase any shares in 2012 and does not plan to repurchase shares during 2013, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock, which do not count against its stock repurchase authorization.

Accumulated Other Comprehensive Income (Loss)

Presented in the table below is a summary of AOCI by component:

At December 31,	2012			2011
(millions)
Dominion
Net unrealized losses on derivatives-hedging activities, net of tax of $87 and $48	$	(122	)	$	(54	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(206) and $(154)	326			243
Net unrecognized pension and other postretirement benefit costs, net of tax of $745 and $568	(1,081		)	(799		)
Total AOCI	$	(877	)	$	(610	)
Virginia Power
Net unrealized losses on derivatives-hedging activities, net of tax of $3 and $2	$	(6	)	$	(3	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(19) and $(14)	31			22
Total AOCI	$	25		$	19

Stock-Based Awards

The 2005 Incentive Compensation Plan permits stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of both plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. At December 31, 2012, approximately 32 million shareswere available for future grants under these plans.

Dominion measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion's results for the years ended December 31, 2012, 2011 and 2010 include $25 million, $39 million, and $40 million,respectively, of compensation costs and $8 million, $13 million, and $15 million, respectively of income tax benefits related to Dominion's stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion's Consolidated Statements of Income. Excess tax benefits are classified as a financing cash flow. During the years ended December 31, 2012, 2011 and 2010, Dominion realized $10 million, $2 million, and $10 million, respectively, of excess tax benefits from the vesting of restricted stock awards and exercise of stock options.

STOCK OPTIONS

The following table provides a summary of changes in amounts of stock options outstanding as of and for the years ended December 31, 2012, 2011 and 2010. No options were granted under any plan in 2012, 2011 or 2010.

	Shares		Weighted - average Exercise Price		Weighted - average Remaining Contractual Life	Aggregated Intrinsic Value(1)
	(thousands)				(years)	(millions)
Outstanding and exercisable at December 31, 2009	3,822		$	31.25		29
Exercised	(1,983	)	$	30.81		$	22
Forfeited/expired	(29	)	$	29.84
Outstanding and exercisable at December 31, 2010	1,810		$	31.76		$	20
Exercised	(1,174	)	$	32.46		$	17
Forfeited/expired	(8	)	$	31.57
Outstanding and exercisable at December 31, 2011	628		$	30.81		$	14
Exercised	(622	)	$	30.79		$	13
Forfeited/expired	(6	)	$	32.26
Outstanding and exercisable at December 31, 2012	—		$	—	—	$	—

(1) Intrinsic value represents the difference between the exercise price of the option and the market value of Dominion's stock.

Dominion issues new shares to satisfy stock option exercises. Dominion received cash proceeds from the exercise of stock options of approximately $19 million, $38 million, and $63 million in the years ended December 31, 2012, 2011 and 2010, respectively.

RESTRICTED STOCK

Restricted stock grants are made to officers under Dominion's LTIP and may also be granted to certain key contributors from time to time. The fair value of Dominion's restricted stock awards is equal to the market price of Dominion's stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2012, 2011 and 2010:

	Shares		Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2009	1,484		$	39.88
Granted	463		38.80
Vested	(618	)	43.54
Cancelled and forfeited	(39	)	36.92
Converted from goal-based stock to restricted stock	186		40.84
Nonvested at December 31, 2010	1,476		$	38.20
Granted	299		43.68
Vested	(617	)	40.72
Cancelled and forfeited	(25	)	36.29
Converted from goal-based stock to restricted stock	168		30.99
Nonvested at December 31, 2011	1,301		$	37.37
Granted	390		51.14
Vested	(596	)	33.31
Cancelled and forfeited	(10	)	42.99
Nonvested at December 31, 2012	1,085		$	44.46

As of December 31, 2012, unrecognized compensation cost related to nonvested restricted stock awards totaled $23 million and is expected to be recognized over a weighted-average period of 2.1 years. The fair value of restricted stock awards that vested was $30 million, $28 million, and $26 million in 2012, 2011 and 2010, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion stock and the applicable federal, state and local tax withholding rates.

GOAL-BASED STOCK

Goal-based stock awards are granted under Dominion's LTIP to officers who have not achieved a certain targeted level of share ownership, in lieu of cash-based performance grants. Goal-based stock awards may also be made to certain key non-officer employees from time to time. Current outstanding goal-based shares include awards granted to officers in February 2011 and February 2012.

The issuance of awards is based on the achievement of two performance metrics during a two-year period, including TSR relative to that of a peer group of companies and ROIC for 2011 and, for 2012, the two metrics of TSR relative to that of companies listed as members of the Philadelphia Stock Exchange Utility Index as of the end of the performance period and ROIC. The actual number of shares issued will vary between zero and 200% of targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is equal to the market price of Dominion's stock on the date of grant. Goal-based stock awards granted to key non-officer employees convert to restricted stock at the end of the two-year performance period and generally vest three years from the original grant date. Awards to officers vest at the end of the two-year performance period. All goal-based stock awards are settled by issuing new shares.

After the performance period for the April 2009 grants ended on December 31, 2010, the CGN Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 132 thousand shares of the outstanding goal-based stock awards granted in April 2009 were converted to 168 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2012. For awards to officers, 20 thousand shares of the outstanding goal-based stock awards were converted to 25 thousand non-restricted shares and issued to the officers.

After the performance period for the April 2010 grants ended on December 31, 2011, the CGN Committee determined the actual performance against metrics established for those awards. For awards to officers, 9 thousand shares of the outstanding goal-based stock awards were converted to 15 thousand non-restricted shares and issued to the officers.

The following table provides a summary of goal-based stock activity for the years ended December 31, 2012, 2011 and 2010:

	Targeted Number of Shares		Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2009	323		$	36.12
Granted	9		37.46
Vested	(16	)	39.31
Cancelled and forfeited	(8	)	30.99
Converted from goal-based stock to restricted stock	(147	)	40.84
Nonvested at December 31, 2010	161		$	31.79
Granted	3		43.54
Vested	(20	)	34.62
Converted from goal-based stock to restricted stock	(132	)	30.99
Nonvested at December 31, 2011	12		$	39.19
Granted	1		52.48
Vested	(9	)	37.46
Nonvested at December 31, 2012	4		$	45.60

At December 31, 2012, the targeted number of shares expected to be issued under the February 2011 and February 2012 awards was approximately 4 thousand. In January 2013, the CGN Committee determined the actual performance against metrics established for the February 2011 awards with a performance period that ended December 31, 2012. Based on that determination, the total number of shares to be issued under the February 2011 goal-based stock awards was approximately 2 thousand.

As of December 31, 2012, unrecognized compensation cost related to nonvested goal-based stock awards was not material.

CASH-BASED PERFORMANCE GRANTS

Cash-based performance grants are made to Dominion's officers under Dominion's LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.

The targeted amount of the cash-based performance grant made to officers in April 2009 was $11 million, but the actual payout of the award in February 2011 determined by the CGN Committee was $14 million ($11 million of which was paid in December 2010), based on the level of performance metrics achieved.

In February 2010, a cash-based performance grant was made to officers. A portion of the grant, representing $14 million was paid in December 2011, based on the achievement of two performance metrics during 2010 and 2011: ROIC and TSR relative to that of a peer group of companies. The total amount of the award under the grant was $20 million and the remaining $6 million of the grant was paid in February 2012. At December 31, 2011, a liability of $5 million had been accrued for the remaining portion of the award.

In February 2011, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $6 million was paid in December 2012, based on the achievement of two performance metrics during 2011 and 2012: TSR relative to that of a peer group of companies and ROIC. The total expected award under the grant is $8 million and the remaining portion of the grant is expected to be paid by March 15, 2013. At December 31, 2012, a liability of $2 million had been accrued for the remaining portion of the award.

In February 2012, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2014 based on the achievement of two performance metrics during 2012 and 2013: TSR relative to that of companies listed as members of the Philadelphia Stock Exchange Utility Index as of the end of the performance period and ROIC. At December 31, 2012, the targeted amount of the grant was $12 million and a liability of $6 million had been accrued for this award.

XML

Preferred Stock

12 Months Ended

Dec. 31, 2012

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Preferred Stock

PREFERRED STOCK

Dominion is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2012 or 2011.

Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference, and had 2.59 million preferred shares issued and outstanding at December 31, 2012 and 2011. Upon involuntary liquidation, dissolution or winding-up of Virginia Power, each share would be entitled to receive $100 plus accrued cumulative dividends.

Holders of Virginia Power's outstanding preferred stock are not entitled to voting rights except under certain provisions of the amended and restated articles of incorporation and related provisions of Virginia law restricting corporate action, upon default in dividends or in special statutory proceedings and as required by Virginia law (such as mergers, consolidations, sales of assets, dissolution and changes in voting rights or priorities of preferred stock).

Presented below are the series of Virginia Power preferred stock that were outstanding as of December 31, 2012:

Dividend	Issued and Outstanding Shares	Entitled Per  Share Upon Liquidation
	(thousands)
$5.00	107	$	112.50
4.04	13	102.27
4.20	15	102.50
4.12	32	103.73
4.80	73	101.00
7.05	500	100.36		(1)
6.98	600	100.35		(2)
Flex Money Market Preferred 12/02, Series A	1,250	100.00		(3)
Total	2,590

(1) Through 7/31/2013; $100.00 commencing 8/1/2013.

(2) Through 8/31/2013; $100.00 commencing 9/1/2013.

(3) Dividend rate was 6.25% until 3/20/2011. Effective 3/20/11 the rate reset to 6.12% until 3/20/2014 after which the rate will be determined according to periodic auctions for periods established by Virginia Power at the time of the auction process.

XML

Variable Interest Entities (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended
	Oct. 31, 2010	Dec. 31, 2012	Dec. 31, 2012 Virginia Electric and Power Company MW	Dec. 31, 2011 Virginia Electric and Power Company	Dec. 31, 2010 Virginia Electric and Power Company
Variable Interest Entity [Line Items]
Aggregate generation capacity from long-term power and capacity contracts (MW)			870
Contracts exprity date start range			2015
Contracts exprity date end range			2021
Remaining purchase commitments			$ 1,100,000,000
Payment for electric capacity			214,000,000	211,000,000	213,000,000
Payment for electric energy			83,000,000	125,000,000	164,000,000
Shared services purchased			328,000,000	389,000,000	465,000,000
Annual lease payments		53,000,000
Option price to purchase at end of lease		923,000,000
Percent of original project cost		70.75%
Fair value of property plant and equipment	957,000,000
Amount of debt expected to be recorded from consolidation	896,000,000
Amount of non-controlling interest expected to be recorded from consolidation	$ 61,000,000

XML

Related Party Transactions (Tables) (Virginia Electric and Power Company)

12 Months Ended

Dec. 31, 2012

Virginia Electric and Power Company

Related Party Transaction [Line Items]

Schedules Of Transactions With Affiliates

Presented below are significant transactions with DRS and other affiliates:

Year Ended December 31,	2012		2011		2010
(millions)
Commodity purchases from affiliates	$	368	$	376	$	373
Services provided by affiliates	399		393		469
Services provided to affiliates	19		21		19

XML

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Earnings Per Share Computation

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

	2012		2011		2010
(millions, except EPS)
Net income attributable to Dominion	$	302	$	1,408	$	2,808
Average shares of common stock outstanding-Basic	572.9		573.1		588.9
Net effect of potentially dilutive securities(1)	1.0		1.5		1.2
Average shares of common stock outstanding-Diluted	573.9		574.6		590.1
Earnings Per Common Share-Basic	$	0.53	$	2.46	$	4.77
Earnings Per Common Share-Diluted	$	0.53	$	2.45	$	4.76

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

XML

Dividend Restrictions

12 Months Ended

Dec. 31, 2012

Disclosure of Restrictions on Dividends, Loans and Advances Disclosure [Abstract]

Dividend Restrictions

DIVIDEND RESTRICTIONS

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2012, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

Certain agreements associated with Dominion's and Virginia Power's credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion's or Virginia Power's ability to pay dividends or receive dividends from their subsidiaries at December 31, 2012.

See Note 17 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes.

XML

Employee Benefit Plans

12 Months Ended

Dec. 31, 2012

General Discussion of Pension and Other Postretirement Benefits [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

DOMINION

Dominion provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit plans, Dominion reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee's compensation. Dominion's funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension program also provides benefits to certain retired executives under a company-sponsored nonqualified employee benefit plan. The nonqualified plan is funded through contributions to a grantor trust. Dominion also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service.

Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and the rate of compensation increases.

Dominion uses December 31 as the measurement date for all of its employee benefit plans. Dominion uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.

Dominion's pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Aggregate actual returns for Dominion's pension and other postretirement plan assets were $743 million in 2012 and $273 million in 2011, versus expected returns of $509 million and $519 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

In January 2011, Dominion amended its retiree healthcare and life benefits to change the eligibility age, effective January 1, 2012, for the majority of nonunion employees from 55 with 10 years of service to 58 with 10 years of service, resulting in an approximately $71 million reduction to the other postretirement benefit plan obligation. The eligibility requirements for nonunion employees hired on or after January 1, 2008, who benefit under the Retiree Medical Account design, as well as for union employees were not affected by this plan design change.

The Medicare Act introduced a federal subsidy to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Dominion determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D. Dominion received a federal subsidy of $5 million for each of 2012 and 2011. In December 2011, Dominion elected to change its method of receiving the subsidy under Medicare Part D for retiree prescription drug coverage from the Retiree Drug Subsidy to the EGWP. This change became effective January 1, 2013. As a result of this change, Dominion recognized a decrease in its other postretirement benefit obligations of approximately $170 million as of December 31, 2011. As a result of the adoption of the EGWP, beginning in 2013 Dominion will receive an increased level of Medicare Part D subsidies, in the form of reduced costs rather than a direct reimbursement.

Funded Status

The following table summarizes the changes in Dominion's pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans' funded status:

	Pension Benefits						Other Postretirement Benefits
Year Ended December 31,	2012			2011			2012			2011
(millions, except percentages)
Changes in benefit obligation:
Benefit obligation at beginning of year	$	4,981		$	4,490		$	1,493		$	1,707
Service cost	116			108			44			48
Interest cost	268			258			79			94
Benefits paid	(208		)	(215		)	(88		)	(83		)
Actuarial (gains) losses during the year	967			340			191			(210		)
Plan amendments	1			—			1			(70		)
Settlements and curtailments(2)	—			—			(6		)	(1		)
Medicare Part D reimbursement	—			—			5			5
Early Retirement Reimbursement Program	—			—			—			3
Benefit obligation at end of year	$	6,125		$	4,981		$	1,719		$	1,493
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	5,145		$	5,106		$	1,042		$	1,031
Actual return on plan assets	611			247			132			26
Employer contributions	5			7			16			19
Benefits paid	(208		)	(215		)	(34		)	(34		)
Fair value of plan assets at end of year	$	5,553		$	5,145		$	1,156		$	1,042
Funded status at end of year	$	(572	)	$	164		$	(563	)	$	(451	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	701			677			1			4
Other current liabilities	(2		)	(3		)	(4		)	(3		)
Noncurrent pension and other postretirement benefit liabilities	(1,271		)	(510		)	(560		)	(452		)
Net amount recognized	$	(572	)	$	164		$	(563	)	$	(451	)
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate	4.4		%	5.5		%	4.4		%	5.5		%
Weighted average rate of increase for compensation	4.21		%	4.21		%	4.22		%	4.22		%

The ABO for all of Dominion's defined benefit pension plans was $5.5 billion and $4.5 billion at December 31, 2012 and 2011, respectively.

Under its funding policies, Dominion evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion determines the amount of contributions for the current year, if any, at that time. During 2012, Dominion made no contributions to its qualified defined benefit pension plans and no contributions are currently expected in 2013. In July 2012, the Moving Ahead for Progress in the 21^st Century Act was signed into law. This Act includes an increase in the interest rates used to determine plan sponsors' pension contributions for required funding purposes. These new interest rates are expected to reduce required pension contributions for 2013 through 2015. Dominion believes that required pension contributions will rise subsequent to 2015, resulting in little net impact to cumulative required contributions over a 10-year period.

Certain regulatory authorities have held that amounts recovered in utility customers' rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion's subsidiaries fund other postretirement benefit costs through VEBAs. Dominion's remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion expects to contribute approximately $14 million to the Dominion VEBAs in 2013.

Dominion does not expect any pension or other postretirement plan assets to be returned to the Company during 2013.

The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets:

	Pension Benefits				Other Postretirement Benefits
As of December 31,	2012		2011		2012		2011
(millions)
Benefit obligation	$	5,462	$	4,416	$	1,591	$	1,375
Fair value of plan assets	4,189		3,903		1,027		920

The following table provides information on the ABO and fair value of plan assets for pension plans with an ABO in excess of plan assets:

As of December 31,	2012(1)		2011
(millions)
Accumulated benefit obligation	$	4,850	$	95
Fair value of plan assets	4,189		—

(1) The increase from 2011 is primarily due to a decrease in the discount rate.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Estimated Future Benefit Payments
	Pension Benefits		Other  Postretirement Benefits
(millions)
2013	$	231	$	89
2014	245		93
2015	255		96
2016	300		100
2017	334		103
2018-2022	1,749		555

Plan Assets

Dominion's overall objective for investing its pension and other postretirement plan assets is to achieve the best possible long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for its pension funds are 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the United States. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the United States including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity REITs and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.

Strategic investment policies are established for Dominion's prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans' strategic allocation are a function of Dominion's assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans' actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.

For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.

The fair values of Dominion's pension plan assets by asset category are as follows:

	Fair Value Measurements
	Pension Plans
At December 31,	2012								2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	—	$	195	—		$	195	1		$	84	—		$	85
U.S. equity:
Large Cap	927		104		—		1,031		805		123		—		928
Other	425		99		—		524		359		197		—		556
Non-U.S. equity:
Large Cap	313		68		—		381		253		58		—		311
Other	228		167		—		395		190		81		—		271
Fixed income:
Corporate debt instruments	27		1,026		—		1,053		36		834		—		870
U.S. Treasury securities and agency debentures	331		304		—		635		304		392		—		696
State and municipal	1		71		—		72		2		77		—		79
Other securities	5		43		—		48		8		40		—		48
Real estate:
REITs	29		—		—		29		16		—		—		16
Partnerships	—		—		321		321		—		—		304		304
Other alternative investments:
Private equity	—		—		456		456		—		—		448		448
Debt	—		—		192		192		—		—		243		243
Hedge funds	—		—		221		221		—		—		290		290
Total	$	2,286	$	2,077	$	1,190	$	5,553	$	1,974	$	1,886	$	1,285	$	5,145

The fair values of Dominion's other postretirement plan assets by asset category are as follows:

	Fair Value Measurements
	Other Postretirement Plans
At December 31,	2012								2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	—	$	13	$	—	$	13	$	—	$	5	$	—	$	5
U.S. equity:
Large Cap	378		5		—		383		38		288		—		326
Other	21		45		—		66		17		44		—		61
Non-U.S. equity:
Large Cap	93		3		—		96		77		3		—		80
Other	11		8		—		19		9		4		—		13
Fixed income:
Corporate debt instruments	1		160		—		161		2		149		—		151
U.S. Treasury securities and agency debentures	16		266		—		282		14		246		—		260
State and municipal	—		9		—		9		—		6		—		6
Other securities	—		2		—		2		—		2		—		2
Real estate:
REITs	1		—		—		1		1		—		—		1
Partnerships	—		—		24		24		—		—		24		24
Other alternative investments:
Private equity	—		—		58		58		—		—		63		63
Debt	—		—		31		31		—		—		36		36
Hedge funds	—		—		11		11		—		—		14		14
Total	$	521	$	511	$	124	$	1,156	$	158	$	747	$	137	$	1,042

The following table presents the changes in Dominion's pension and other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category:

	Fair Value Measurements using Significant Unobservable Inputs (Level 3)
	Pension Plans															Other Postretirement Plans
	Real Estate			Private Equity			Debt			Hedge Funds			Total			Real Estate			Private Equity			Debt			Hedge Funds			Total
Balance at December 31, 2009	$	344		$	344		$	241		$	388		$	1,317		$	26		$	54		$	36		$	19		$	135
Actual return on plan assets:
Relating to assets still held at the reporting date	8			56			27			27			118			—			9			2			1			12
Purchases	56			90			36			—			182			3			9			8			—			20
Sales	(137		)	(90		)	(42		)	(70		)	(339		)	(7		)	(11		)	(6		)	(3		)	(27		)
Balance at December 31, 2010	$	271		$	400		$	262		$	345		$	1,278		$	22		$	61		$	40		$	17		$	140
Actual return on plan assets:
Relating to assets still held at the reporting date	38			70			10			10			128			3			11			1			—			15
Relating to assets sold during the period	(8		)	(34		)	(10		)	(15		)	(67		)	—			(4		)	(1		)	(1		)
Purchases	57			76			34			48			215			3			8			3			2			16
Sales	(54		)	(64		)	(53		)	(98		)	(269		)	(4		)	(13		)	(7		)	(4		)	(28		)
Balance at December 31, 2011	$	304		$	448		$	243		$	290		$	1,285		$	24		$	63		$	36		$	14		$	137
Actual return on plan assets:
Relating to assets still held at the reporting date	21			46			17			21			105			1			3			4			1			9
Relating to assets sold during the period	(8		)	(41		)	(11		)	(2		)	(62		)	—			(1		)	—			—			(1		)
Purchases	35			79			15			—			129			2			6			1			—			9
Sales	(31		)	(76		)	(72		)	(88		)	(267		)	(3		)	(13		)	(10		)	(4		)	(30		)
Balance at December 31, 2012	$	321		$	456		$	192		$	221		$	1,190		$	24		$	58		$	31		$	11		$	124

Net Periodic Benefit Cost

The components of the provision for net periodic benefit cost and amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:

	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2012			2011			2010			2012			2011			2010
(millions, except percentages)
Service cost	$	116		$	108		$	102		$	44		$	48		$	56
Interest cost	268			258			266			79			94			101
Expected return on plan assets	(430		)	(440		)	(410		)	(79		)	(79		)	(69		)
Amortization of prior service (credit) cost	3			3			3			(13		)	(13		)	(7		)
Amortization of net actuarial loss	132			96			59			6			12			12
Settlements and curtailments(1)	—			—			136			(4		)	1			37
Special termination benefits(2)	—			—			10			—			—			1
Net periodic benefit (credit) cost	$	89		$	25		$	166		$	33		$	63		$	131
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	786		$	534		$	95		$	139		$	(157	)	$	13
Prior service (credit) cost	—			—			1			1			(70		)	—
Settlements and curtailments(1)	—			—			(50		)	(2		)	(1		)	(1		)
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss	(132		)	(96		)	(59		)	(6		)	(12		)	(12		)
Amortization of prior service credit (cost)	(3		)	(3		)	(3		)	13			13			7
Total recognized in other comprehensive income and regulatory assets and liabilities	$	651		$	435		$	(16	)	$	145		$	(227	)	$	7
Significant assumptions used to determine periodic cost:
Discount rate	5.5		%	5.9		%	6.6		%	5.5		%	5.9		%	6.6		%
Expected long-term rate of return on plan assets	8.5		%	8.5		%	8.5		%	7.75		%	7.75		%	7.75		%
Weighted average rate of increase for compensation	4.21		%	4.61		%	4.76		%	4.22		%	4.62		%	4.79		%
Healthcare cost trend rate(3)										7		%	7		%	7		%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(3)										4.6		%	4.6		%	4.6		%
Year that the rate reaches the ultimate trend rate(3)										2061			2060			2060

(1) 2012 amounts relate to the sale of Salem Harbor. 2010 amounts relate to the sales of Peoples and Dominion's Appalachian E&P operations and a workforce reduction program.

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

(3) Assumptions used to determine periodic cost for the following year.

The components of AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit cost are as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2012		2011		2012			2011
(millions)
Net actuarial loss	$	2,865	$	2,211	$	230		$	100
Prior service (credit) cost	11		14		(71		)	(86		)
Total(1)	$	2,876	$	2,225	$	159		$	14

(1) As of December 31, 2012, of the $2.9 billion and $158 million related to pension benefits and other postretirement benefits, $1.8 billion and$69 million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2011, of the $2.2 billion related to pension benefits, $1.4 billion is included in AOCI, with the remainder included in regulatory assets and liabilities; the $14 million related to other postretirement benefits consists of $16 million included in regulatory assets and liabilities and $(2) million included in AOCI.

The following table provides the components of AOCI and regulatory assets and liabilities as of December 31, 2012 that are expected to be amortized as components of periodic benefit cost in 2013:

	Pension Benefits		Other Postretirement Benefits
(millions)
Net actuarial loss	$	185	$	9
Prior service (credit) cost	3		(12		)

Dominion determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans by using a combination of:

• Expected inflation and risk-free interest rate assumptions;

• Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;

• Expected future risk premiums, asset volatilities and correlations;

• Forecasts of an independent investment advisor;

• Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major stock market indices; and    

• Investment allocation of plan assets.

Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans.

Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion's retiree healthcare plans. A one percentage point change in assumed healthcare cost trend rates would have had the following effects:

	Other Postretirement Benefits
	One percentage point increase		One percentage point decrease
(millions)
Effect on total of service and interest cost components for 2012	$	17	$	(16	)
Effect on other postretirement benefit obligation at December 31, 2012	218		(172		)

An internal committee selects the final assumptions used for Dominion's pension and other postretirement plans, including discount rates, expected long-term rates of return and healthcare cost trend rates.

Defined Contribution Plans

In addition, Dominion sponsors defined contribution employee savings plans. During 2012, 2011 and 2010, Dominion recognized $40 million, $38 million and $39 million, respectively, as employer matching contributions to these plans.

VIRGINIA POWER

Virginia Power participates in the Dominion Pension Plan, a defined benefit pension plan sponsored by Dominion that provides benefits to multiple Dominion subsidiaries. Retirement benefits payable under this plan are based primarily on years of service, age and the employee's compensation. As a participating employer, Virginia Power is subject to Dominion's funding policy, which is to contribute annually an amount that is in accordance with the provisions of ERISA. During 2012 Virginia Power made no contributions to the plan and no contributions are currently expected in 2013. Virginia Power's net periodic pension cost related to this pension plan was $72 million, $50 million and $84 million in 2012, 2011 and 2010, respectively. Employee compensation is the basis for determining Virginia Power's share of total pension costs.

Virginia Power also participates in the Dominion Retiree Health and Welfare Plan, a plan sponsored by Dominion that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Annual employee premiums are based on several factors such as age, retirement date and years of service. Virginia Power's net periodic benefit cost related to this plan was $13 million, $23 million and $59 million in 2012, 2011 and 2010, respectively. Employee headcount is the basis for determining Virginia Power's share of total other postretirement benefit costs.

Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power funds other postretirement benefit costs through a VEBA. Virginia Power made no contributions to the VEBA in 2012 and does not expect to contribute to the VEBA in 2013.

Dominion holds investments in trusts to fund employee benefit payments for its pension and other postretirement benefit plans, in which Virginia Power's employees participate. Any investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power will provide to Dominion for its share of employee benefit plan contributions.

Virginia Power also participates in Dominion-sponsored defined contribution employee savings plans that cover substantially all employees. Employer matching contributions of $15 million were incurred in 2012 and $14 million in each of 2011 and 2010.

XML

Consolidated Statements Equity (USD $) In Millions, unless otherwise specified		Total		Common Stock	Other Paid-In Capital	Retained Earnings		Accumulated Other Comprehensive Income (Loss)	Total Common Shareholders' Equity		Noncontrolling Interests	Virginia Electric and Power Company	Virginia Electric and Power Company Common Stock	Virginia Electric and Power Company Other Paid-In Capital	Virginia Electric and Power Company Retained Earnings	Virginia Electric and Power Company Accumulated Other Comprehensive Income (Loss)
Beginning Balance, value at Dec. 31, 2009		$ 11,185		$ 6,525	$ 185	$ 4,686		$ (211)	$ 11,185		$ 0	$ 7,173	$ 4,738	$ 1,110	$ 1,299	$ 26
Beginning Balance (in shares) at Dec. 31, 2009				599									242
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests		2,825	[1]			2,825			2,825
Net income attributable to Dominion		2,808	[1]									852			852
Consolidation of noncontrolling interests, (in shares)				1									33
Consolidation of noncontrolling interests, value		10		10					10			1,000	1,000
Stock awards and stock options exercised (net of change in unearned compensation) (in shares)				2
Stock awards and stock options exercised (net of change in unearned compensation), value		80		80					80
Other stock issuances (in shares)				(21)
Other stock issuances, value		(900)		(900)					(900)
Tax benefit from stock awards and stock options exercised		9			9				9
Dividends		(1,093)	[2]			(1,093)	[2]		(1,093)	[2]		(517)			(517)
Tax benefit from stock awards and stock options exercised		15										1		1
Other comprehensive loss, net of tax		(119)						(119)	(119)			(2)				(2)
Beginning Balance, value at Dec. 31, 2010		11,997		5,715	194	6,418		(330)	11,997			8,507	5,738	1,111	1,634	24
Ending Balance (shares) at Dec. 31, 2010				581									275
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests	[3]	483
Net income attributable to Dominion		479	[3]									278
Beginning Balance, value at Mar. 31, 2011
Beginning Balance, value at Dec. 31, 2010		11,997		5,715	194	6,418		(330)	11,997		0	8,507			1,634	24
Beginning Balance (in shares) at Dec. 31, 2010				581
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests		1,426	[1]			1,425			1,425		1
Net income attributable to Dominion		1,408	[1]									822			822
Noncontrolling Interest, Increase from Business Combination	[4]	61									61
Consolidation of noncontrolling interests, (in shares)				1
Consolidation of noncontrolling interests, value		49		49					49
Stock awards and stock options exercised (net of change in unearned compensation) (in shares)				(13)
Stock awards and stock options exercised (net of change in unearned compensation), value		(601)		(601)					(601)
Stock repurchases (in shares)	[5]			1
Stock repurchases, value	[5]	0		17	(17)				0
Tax benefit from stock awards and stock options exercised		2			2				2
Dividends		(1,151)				(1,146)	[2]		(1,146)		(5)	(574)			(574)
Tax benefit from stock awards and stock options exercised		13
Other comprehensive loss, net of tax		(280)						(280)	(280)			(5)				(5)
Beginning Balance, value at Dec. 31, 2011		11,503		5,180	179	6,697		(610)	11,446		57	8,750	5,738		1,882	19
Ending Balance (shares) at Dec. 31, 2011				570									275
Beginning Balance, value at Sep. 30, 2011
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests		207
Net income attributable to Dominion		201										6
Beginning Balance, value at Dec. 31, 2011		11,503										8,750	5,738
Ending Balance (shares) at Dec. 31, 2011													275
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests	[3]	501
Net income attributable to Dominion		494	[3]									243
Beginning Balance, value at Mar. 31, 2012
Beginning Balance, value at Dec. 31, 2011		11,503		5,180	179	6,697		(610)	11,446		57	8,750	5,738	1,111	1,882	19
Beginning Balance (in shares) at Dec. 31, 2011				570									275
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests		329				318			318		11
Net income attributable to Dominion		302										1,050			1,050
Consolidation of noncontrolling interests, (in shares)				4
Consolidation of noncontrolling interests, value		246		246					246
Stock awards and stock options exercised (net of change in unearned compensation) (in shares)				1
Stock awards and stock options exercised (net of change in unearned compensation), value		26		26					26
Other stock issuances (in shares)	[5]			1
Other stock issuances, value	[5]	14		41	(27)				14
Tax benefit from stock awards and stock options exercised		10			10				10
Dividends		(1,236)				(1,225)	[2]		(1,225)		(11)	(575)			(575)
Tax benefit from stock awards and stock options exercised		8										2		2
Other comprehensive loss, net of tax		(267)						(267)	(267)			6				6
Beginning Balance, value at Dec. 31, 2012		10,625		5,493	162	5,790		(877)	10,568		57	9,233	5,738	1,113	2,357	25
Ending Balance (shares) at Dec. 31, 2012				576									275
Beginning Balance, value at Sep. 30, 2012
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests		(652)
Net income attributable to Dominion		(659)										220
Beginning Balance, value at Dec. 31, 2012		$ 10,625										$ 9,233	$ 5,738
Ending Balance (shares) at Dec. 31, 2012													275

[1] Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

[2] Includes subsidiary preferred dividends related to noncontrolling interests of $16 million in 2012 and $17 million in 2011 and 2010.

[3] Revenue and income amounts have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

[4] See Note 15 for consolidation of a VIE in October 2011.

[5] Contains shares issued in excess of principal amounts related to converted securities. See Note 17 for further information on convertible securities.

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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

Environmental Matters

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

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

In December 2011, the EPA issued MATS for coal and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance will be required by April 16, 2015, with certain limited exceptions. In December 2011, Virginia Power recorded a $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain regulated coal units, primarily as a result of the issuance of the final MATS. Dominion continues to be governed by individual state mercury emission reduction regulations in Massachusetts and Illinois that are largely unaffected by this rule.

The EPA established CAIR with the intent to require significant reductions in SO₂ and NO_X emissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO₂ and NO_x emissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO₂ and NO_x emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NO_x emissions caps, NO_x emissions caps during the ozone season (May 1 through September 30) and annual SO₂ emission caps with differing requirements for two groups of affected states.

Following numerous petitions by industry participants for review and motions for stay, the U.S. Court of Appeals for the D.C. Circuit issued a ruling in December 2011 to stay CSAPR pending judicial review. In February and June 2012, the EPA issued technical revisions to CSAPR that are not material to Dominion. In August 2012, the Court vacated CSAPR in its entirety and ordered the EPA to implement CAIR until a valid replacement rule is issued. In October 2012, the EPA filed a petition requesting a rehearing of the court's decision, which was denied in January 2013. The mandate vacating CSAPR was issued February 4, 2013. The stay of CSAPR remains in effect and the EPA will continue to administer CAIR until such time that the EPA develops and implements new rulemaking addressing the issues identified by the Court. With respect to Dominion's generation fleet, the cost to comply with CAIR is not expected to be material. Future outcomes of litigation and/or any additional action to issue a revised rule could affect the assessment regarding cost of compliance.

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

In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, NSPS, the Title V permit program and the stations' respective State Implementation Plans. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA's enforcement authority under the CAA. In May 2010, 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 Brayton Point. Dominion submitted its response to the request in November 2010.

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

WATER

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

In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. As of the end of the third quarter of 2012, the station was fully converted to closed cycle cooling. The total cost to install these cooling towers was approximately $550 million. See Note 6 for a discussion of impairments related to Brayton Point.

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

SOLID AND HAZARDOUS WASTE

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

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

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

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

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

CLIMATE CHANGE LEGISLATION AND REGULATION

Massachusetts, Rhode Island and Connecticut, among other states, have joined RGGI, a multi-state effort to reduce CO₂ emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO₂ emissions from power plants in participating states are required to be stabilized at current levels from 2009 to 2015. Further reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO₂ emissions. During 2012, RGGI underwent a program review, and in February 2013, revisions to the RGGI model rule were issued.  Dominion is in the process of evaluating these revisions as to potential impacts on Dominion's fossil fired generation operations in RGGI states.  Until this evaluation is completed, Dominion is unable to estimate the potential financial statement impacts related to the program review.

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

MF Global

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

In accordance with court-approved procedures, Dominion transferred to other FCMs all open positions executed using MF Global. The initial margin posted for these open positions at October 31, 2011 was approximately $73 million. Dominion had received approximately $17 million of this amount through the liquidation process as of December 31, 2012.  In January 2013, Dominion sold the remaining claims of approximately $56 million to a third party at a small discount.

Nuclear Matters

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

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

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

Long-Term Purchase Agreements

At December 31, 2012, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:

	2013		2014		2015		2016		2017		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	350	$	358	$	337	$	275	$	181	$	327	$	1,828

(1) Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2012, the present value of Virginia Power's total commitment for capacity payments is $1.4 billion. Capacity payments totaled $337 million, $338 million, and $344 million, and energy payments totaled $214 million, $275 million, and $303 million for 2012, 2011 and 2010, respectively.

Lease Commitments

Dominion and Virginia Power lease various facilities, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2012 are as follows:

	2013		2014		2015		2016		2017		Thereafter		Total
(millions)
Dominion	$	79	$	72	$	64	$	55	$	63	$	161	$	494
Virginia Power	$	26	$	24	$	19	$	15	$	11	$	26	$	121

Rental expense for Dominion totaled $112 million, $155 million, and $171 million for 2012, 2011 and 2010, respectively. Rental expense for Virginia Power totaled $48 million, $50 million, and $50 million for 2012, 2011, and 2010, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.

Nuclear Operations

Nuclear Decommissioning - Minimum Financial Assurance

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 2012 calculation for the NRC minimum financial assurance amount, aggregated for Dominion's and Virginia Power's nuclear units, excluding joint owners' assurance amounts, was $3.3 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2012 NRC minimum financial assurance amounts shown were calculated using preliminary December 31, 2012 U.S. Bureau of Labor Statistics indices. Dominion believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion and Virginia Power will continue to monitor these trusts to ensure they meet the minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC. See Note 6 to the Consolidated Financial Statements for additional information on Kewaunee.

Nuclear Insurance

The Price-Anderson Amendments Act of 1988 provides the public up to $12.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $118 million for each of their licensed reactors not to exceed $18 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

The current level of property insurance coverage for Dominion's and Virginia Power's nuclear units is as follows:

	Coverage
(billions)
Dominion
Millstone	$	2.75
Kewaunee	1.80
Virginia Power(1)
Surry	$	2.55
North Anna	2.55

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

The Companies' coverage exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion's and Virginia Power's maximum retrospective premium assessment for the current policy period is $89 million and $48 million, respectively. Based on the severity of the incident, the Board of Directors of NEIL has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

Dominion and Virginia Power also purchase insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, the Companies are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion's and Virginia Power's maximum retrospective premium assessment for the current policy period is $33 million and $20 million, respectively.

During the fourth quarter of 2012, Dominion announced plans to close and decommission Kewaunee.  Kewaunee is expected to cease power production in the second quarter of 2013 and commence decommissioning activities.  Effective February 1, 2013, Kewaunee's accidental outage policy for replacement power costs has been cancelled, and Kewaunee's property coverage of $1.8 billion did not change.  The cancellation of Kewaunee's accidental outage policy for replacement power costs lowered Dominion's retrospective premium assessment from $33 million to $30 million.

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

Spent Nuclear Fuel

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

Dominion and Virginia Power have resolved additional claims for damages incurred at Millstone, Kewaunee, Surry and North Anna. In May 2012, Dominion made formal offers of settlement to the Authorized Representative of the Attorney General for resolution of claims incurred at Millstone for the period July 1, 2006 through December 31, 2010 and periodic payments after that date through 2013, and for resolution of claims incurred at Kewaunee for the period January 1, 2009 through December 31, 2010 and periodic payments after that date through 2013. In September 2012, Dominion and the government entered into settlement agreements. Initial settlement payments in the amounts of $20 million for Millstone and $6 million for Kewaunee were received in the fourth quarter of 2012. In September 2012, Virginia Power made a formal offer of settlement for resolution of claims incurred at Surry and North Anna for the period July 1, 2006 through December 31, 2010 and periodic payments after that date through 2013. In November 2012, Virginia Power and the government entered into a settlement agreement. An initial settlement payment in the amount of $75 million for Surry and North Anna was received in the fourth quarter of 2012. All of the settlement agreements are extendable after 2013 by mutual agreement of the parties. In June 2012, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims for Millstone, Surry and North Anna against the DOE requesting additional damages for the period July 1, 2006 through December 31, 2010. The lawsuits have been dismissed as a result of the settlement agreements.

The Companies continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion's receivables for spent nuclear fuel-related costs totaled $36 million and $102 million at December 31, 2012 and 2011, respectively. Virginia Power's receivables for spent nuclear fuel-related costs totaled $26 million and $76 million at December 31, 2012 and 2011, respectively. The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Guarantees, Surety Bonds and Letters of Credit

DOMINION

At December 31, 2012, Dominion had issued $92 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2012, Dominion's exposure under these guarantees was $62 million, primarily related to certain reserve requirements associated with non-recourse financing.

In addition to the above guarantees, Dominion and its partners, Shell and BP, may be required to make additional periodic equity contributions to NedPower and Fowler Ridge in connection with certain funding requirements associated with their respective non-recourse financings. As of December 31, 2012, Dominion's maximum remaining cumulative exposure under these equity funding agreements is $107 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million.

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

At December 31, 2012, Dominion had issued the following subsidiary guarantees:

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	363	$	363
Commodity transactions(3)	2,939		377
Nuclear obligations(4)	231		77
Other(5)	673		98
Total	$	4,206	$	915

(1) Represents the estimated portion of the guarantee's stated limit that is utilized as of December 31, 2012 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

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

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

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

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

Additionally, as of December 31, 2012 Dominion had purchased $163 million of surety bonds and authorized the issuance of letters of credit by financial institutions of $26 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Dominion is obligated to indemnify the respective surety bond company for any amounts paid.

VIRGINIA POWER

As of December 31, 2012, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. Virginia Power had also purchased $67 million of surety bonds for various purposes, including providing workers' compensation coverage, and authorized the issuance of letters of credit by financial institutions of $2 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Virginia Power is obligated to indemnify the respective surety bond company for any amounts paid.

Indemnifications

As part of commercial contract negotiations in the normal course of business, Dominion and Virginia Power may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. Dominion and Virginia Power are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2012, Dominion and Virginia Power believe future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.

Workforce Reduction Program

In the first quarter of 2010, Dominion and Virginia Power announced a workforce reduction program that reduced their total workforces by approximately 9% and 11%, respectively, during 2010. The goal of the workforce reduction program was to reduce operations and maintenance expense growth and further improve the efficiency of the Companies. In the first quarter of 2010, Dominion recorded a $338 million ($206 million after-tax) charge, including $202 million ($123 million after-tax) at Virginia Power, primarily reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other benefits related to the workforce reduction program. During 2010, Dominion and Virginia Power paid $109 million and $104 million, respectively, of costs related to the program. The terms of the workforce reduction program were consistent with the Companies' existing severance plan.

XML

Investments (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended								1 Months Ended	12 Months Ended			1 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2012 Categories of Investments, Marketable Securities, Trading Securities	Dec. 31, 2011 Categories of Investments, Marketable Securities, Trading Securities	Dec. 31, 2012 Categories of Investments, Cost-method Investments	Dec. 31, 2011 Categories of Investments, Cost-method Investments	Dec. 31, 2012 Blue Racer	Dec. 31, 2012 Blue Racer	Dec. 31, 2011 Blue Racer	Dec. 31, 2010 Blue Racer	Dec. 31, 2012 Other operations and maintenance expense Blue Racer	Dec. 31, 2012 Virginia Electric and Power Company	Dec. 31, 2011 Virginia Electric and Power Company
Gain (Loss) on Investments [Line Items]
Investments held in our rabbi trusts					$ 95	$ 90	$ 14	$ 17
Equity earnings on investments	25	35	42
Company received distribution from Fowler Ridge in connection with non-recourse permanent financing	58	55		60					115	115	0	0
Carrying amount of Company's investments exceeded its shares of underlying equity	30	32
Ownership percentage									50.00%	50.00%
Gain on purchase of business													72
Gain on purchase of business, net of tax													43
Transaction costs on sale													9
Restricted cash and cash equivalent for funding qualifying projects	$ 37	$ 147												$ 10	$ 32

XML

Employee Benefit Plans (Benefit Obligation in Excess of Plan Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	$ 5,462	$ 4,416
Fair value of plan assets	4,189	3,903
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	1,591	1,375
Fair value of plan assets	$ 1,027	$ 920

XML

Operating Revenue (Tables)

12 Months Ended

Dec. 31, 2012

Regulated and Unregulated Operating Revenue [Abstract]

Operating Revenue, Table

Dominion's and Virginia Power's operating revenue consists of the following:

Year Ended December 31,	2012		2011		2010
(millions)
Dominion
Electric sales:
Regulated	$	7,102	$	7,114	$	7,123
Nonregulated	2,742		3,100		3,559
Gas sales:
Regulated	250		287		308
Nonregulated	1,071		1,635		2,010
Gas transportation and storage	1,401		1,506		1,493
Other	527		503		434
Total operating revenue	$	13,093	$	14,145	$	14,927
Virginia Power
Regulated electric sales	$	7,102	$	7,114	$	7,123
Other	124		132		96
Total operating revenue	$	7,226	$	7,246	$	7,219

XML

Shareholders' Equity (Tables)

12 Months Ended

Dec. 31, 2012

Stockholders' Equity Note [Abstract]

Accumulated other comprehensive income (loss)

Presented in the table below is a summary of AOCI by component:

At December 31,	2012			2011
(millions)
Dominion
Net unrealized losses on derivatives-hedging activities, net of tax of $87 and $48	$	(122	)	$	(54	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(206) and $(154)	326			243
Net unrecognized pension and other postretirement benefit costs, net of tax of $745 and $568	(1,081		)	(799		)
Total AOCI	$	(877	)	$	(610	)
Virginia Power
Net unrealized losses on derivatives-hedging activities, net of tax of $3 and $2	$	(6	)	$	(3	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(19) and $(14)	31			22
Total AOCI	$	25		$	19

Summary of changes in amounts of stock options outstanding

The following table provides a summary of changes in amounts of stock options outstanding as of and for the years ended December 31, 2012, 2011 and 2010. No options were granted under any plan in 2012, 2011 or 2010.

	Shares		Weighted - average Exercise Price		Weighted - average Remaining Contractual Life	Aggregated Intrinsic Value(1)
	(thousands)				(years)	(millions)
Outstanding and exercisable at December 31, 2009	3,822		$	31.25		29
Exercised	(1,983	)	$	30.81		$	22
Forfeited/expired	(29	)	$	29.84
Outstanding and exercisable at December 31, 2010	1,810		$	31.76		$	20
Exercised	(1,174	)	$	32.46		$	17
Forfeited/expired	(8	)	$	31.57
Outstanding and exercisable at December 31, 2011	628		$	30.81		$	14
Exercised	(622	)	$	30.79		$	13
Forfeited/expired	(6	)	$	32.26
Outstanding and exercisable at December 31, 2012	—		$	—	—	$	—

(1) Intrinsic value represents the difference between the exercise price of the option and the market value of Dominion's stock.

Summary of restricted stock activity

The following table provides a summary of restricted stock activity for the years ended December 31, 2012, 2011 and 2010:

	Shares		Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2009	1,484		$	39.88
Granted	463		38.80
Vested	(618	)	43.54
Cancelled and forfeited	(39	)	36.92
Converted from goal-based stock to restricted stock	186		40.84
Nonvested at December 31, 2010	1,476		$	38.20
Granted	299		43.68
Vested	(617	)	40.72
Cancelled and forfeited	(25	)	36.29
Converted from goal-based stock to restricted stock	168		30.99
Nonvested at December 31, 2011	1,301		$	37.37
Granted	390		51.14
Vested	(596	)	33.31
Cancelled and forfeited	(10	)	42.99
Nonvested at December 31, 2012	1,085		$	44.46

Summary of restricted stock and goal-based stock activity

The following table provides a summary of goal-based stock activity for the years ended December 31, 2012, 2011 and 2010:

	Targeted Number of Shares		Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2009	323		$	36.12
Granted	9		37.46
Vested	(16	)	39.31
Cancelled and forfeited	(8	)	30.99
Converted from goal-based stock to restricted stock	(147	)	40.84
Nonvested at December 31, 2010	161		$	31.79
Granted	3		43.54
Vested	(20	)	34.62
Converted from goal-based stock to restricted stock	(132	)	30.99
Nonvested at December 31, 2011	12		$	39.19
Granted	1		52.48
Vested	(9	)	37.46
Nonvested at December 31, 2012	4		$	45.60

XML

Fair Value Measurements (Assets and Liabilities that are Measured at Fair Value on a Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 84
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	4,175		4,192
Liabilities, Fair Value Disclosure	661		1,157
Fair Value, Measurements, Recurring | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	735		965
Total liabilities	595		888
Fair Value, Measurements, Recurring | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	93		105
Total liabilities	66		269
Fair Value, Measurements, Recurring | Equity securities: | Large Cap | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,973	[1]	1,718	[1]
Fair Value, Measurements, Recurring | Equity securities: | Large Cap | Non-U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	12	[1]	10	[1]
Fair Value, Measurements, Recurring | Equity securities: | Other | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	59	[1]	51	[1]
Fair Value, Measurements, Recurring | Fixed Income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	325	[1]	332	[1]
Fair Value, Measurements, Recurring | Fixed Income: | U.S. Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	543	[1]	458	[1]
Fair Value, Measurements, Recurring | Fixed Income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	315	[1]	329	[1]
Fair Value, Measurements, Recurring | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	7	[1]	23	[1]
Fair Value, Measurements, Recurring | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	80	[1]	60	[1]
Fair Value, Measurements, Recurring | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	33	[1]	141	[1]
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	2,460		2,100
Liabilities, Fair Value Disclosure	8		10
Fair Value, Measurements, Recurring | Level 1 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	12		44
Total liabilities	8		10
Fair Value, Measurements, Recurring | Level 1 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0		0
Total liabilities	0		0
Fair Value, Measurements, Recurring | Level 1 | Equity securities: | Large Cap | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,973	[1]	1,718	[1]
Fair Value, Measurements, Recurring | Level 1 | Equity securities: | Large Cap | Non-U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	12	[1]	10	[1]
Fair Value, Measurements, Recurring | Level 1 | Equity securities: | Other | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	59	[1]	51	[1]
Fair Value, Measurements, Recurring | Level 1 | Fixed Income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 1 | Fixed Income: | U.S. Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	391	[1]	277	[1]
Fair Value, Measurements, Recurring | Level 1 | Fixed Income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 1 | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 1 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	13	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 1 | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	1,631		1,999
Liabilities, Fair Value Disclosure	594		983
Fair Value, Measurements, Recurring | Level 2 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	639		828
Total liabilities	528		714
Fair Value, Measurements, Recurring | Level 2 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	93		105
Total liabilities	66		269
Fair Value, Measurements, Recurring | Level 2 | Equity securities: | Large Cap | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 2 | Equity securities: | Large Cap | Non-U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 2 | Equity securities: | Other | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 2 | Fixed Income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	325	[1]	332	[1]
Fair Value, Measurements, Recurring | Level 2 | Fixed Income: | U.S. Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	152	[1]	181	[1]
Fair Value, Measurements, Recurring | Level 2 | Fixed Income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	315	[1]	329	[1]
Fair Value, Measurements, Recurring | Level 2 | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	7	[1]	23	[1]
Fair Value, Measurements, Recurring | Level 2 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	67	[1]	60	[1]
Fair Value, Measurements, Recurring | Level 2 | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	33	[1]	141	[1]
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	84		93
Liabilities, Fair Value Disclosure	59		164
Fair Value, Measurements, Recurring | Level 3 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	84		93
Total liabilities	59		164
Fair Value, Measurements, Recurring | Level 3 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0		0
Total liabilities	0		0
Fair Value, Measurements, Recurring | Level 3 | Equity securities: | Large Cap | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 3 | Equity securities: | Large Cap | Non-U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 3 | Equity securities: | Other | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 3 | Fixed Income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 3 | Fixed Income: | U.S. Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 3 | Fixed Income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 3 | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 3 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Fair Value, Measurements, Recurring | Level 3 | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	1,409		1,301
Liabilities, Fair Value Disclosure	34		147
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	6		2
Total liabilities	9		47
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total liabilities	25		100
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Equity securities: | Large Cap | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	779	[1]	679	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Equity securities: | Other | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	27	[1]	23	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Fixed Income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	196	[1]	214	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Fixed Income: | U.S. Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	234	[1]	170	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Fixed Income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	118	[1]	125	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1	[1]	16	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	38	[1]	40	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	10	[1]	32	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	981		809
Liabilities, Fair Value Disclosure	0		0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0		0
Total liabilities	0		0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total liabilities	0		0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Equity securities: | Large Cap | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	779	[1]	679	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Equity securities: | Other | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	27	[1]	23	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Fixed Income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Fixed Income: | U.S. Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	168	[1]	107	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Fixed Income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	7	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	423		490
Liabilities, Fair Value Disclosure	31		117
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1		0
Total liabilities	6		17
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total liabilities	25		100
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Equity securities: | Large Cap | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Equity securities: | Other | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Fixed Income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	196	[1]	214	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Fixed Income: | U.S. Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	66	[1]	63	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Fixed Income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	118	[1]	125	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1	[1]	16	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	31	[1]	40	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	10	[1]	32	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	5		2
Liabilities, Fair Value Disclosure	3		30
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5		2
Total liabilities	3		30
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total liabilities	0		0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Equity securities: | Large Cap | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Equity securities: | Other | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Fixed Income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Fixed Income: | U.S. Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Fixed Income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[1]	0	[1]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 0	[1]	$ 0	[1]

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

XML

Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Operating Revenue	$ 13,093		$ 14,145	[1]	$ 14,927	[1]
Operating Expenses
Electric fuel and other energy-related purchases	3,748		4,097	[1]	4,034	[1]
Purchased electric capacity	387		454	[1]	453	[1]
Purchased gas	1,177		1,764	[1]	2,049	[1]
Other operations and maintenance	4,868	[2]	3,322	[1],[2]	3,448	[1],[2]
Depreciation, depletion and amortization	1,186		1,066	[1]	1,035	[1]
Other taxes	571		548	[1]	524	[1]
Total operating expenses	11,937		11,251	[1]	11,543	[1]
Gain on sale of Appalachian E&P operations	0		0	[1]	2,467	[1]
Income from operations	1,156		2,894	[1]	5,851	[1]
Other income	223		178	[1]	170	[1]
Interest and related charges	882		867	[1]	826	[1]
Income from continuing operations including noncontrolling interests before income taxes	497		2,205	[1]	5,195	[1]
Income tax expense	146	[3]	754	[1],[3]	2,112	[1],[3]
Income from continuing operations including noncontrolling interests	351		1,451	[1]	3,083	[1]
Income (loss) from discontinued operations	(22)	[4]	(25)	[1],[4]	(258)	[1],[4]
Net income including noncontrolling interests	329		1,426	[1]	2,825	[1]
Noncontrolling interests	27		18	[1]	17	[1]
Net income attributable to Dominion	302		1,408	[1]	2,808	[1]
Amounts attributable to Dominion:
Income from continuing operations, net of tax	324	[5]	1,433	[1],[5]	3,066	[1]
Loss from discontinued operations, net of tax	(22)		(25)	[1]	(258)	[1]
Net income attributable to Dominion	302		1,408	[1]	2,808	[1]
Earnings Per Common Share-Basic:
Income from continuing operations (in dollars per share)	$ 0.57	[5]	$ 2.50	[1],[5]	$ 5.21	[1]
Loss from discontinued operations (in dollars per share)	$ (0.04)		$ (0.04)	[1],[5]	$ (0.44)	[1]
Net income attributable to Dominion (in dollars per share)	$ 0.53		$ 2.46	[1]	$ 4.77	[1]
Earnings Per Common Share-Diluted:
Income from continuing operations (in dollars per share)	$ 0.57	[5]	$ 2.49	[1],[5]	$ 5.20	[1]
Loss from discontinued operations (in dollars per share)	$ (0.04)		$ (0.04)	[1],[5]	$ (0.44)	[1]
Net income attributable to Dominion (in dollars per share)	$ 0.53		$ 2.45	[1]	$ 4.76	[1]
Dividends declared per common share	$ 2.11		$ 1.97	[1]	$ 1.83	[1]
Virginia Electric and Power Company
Operating Revenue	7,226		7,246		7,219
Operating Expenses
Electric fuel and other energy-related purchases	2,368		2,506		2,495
Purchased electric capacity	386		452		449
Affiliated suppliers	305		306		384
Other	1,161		1,437		1,361
Depreciation, depletion and amortization	782		718		671
Other taxes	232		222		218
Total operating expenses	5,234		5,641		5,578
Income from operations	1,992		1,605		1,641
Other income	96		88		100
Interest and related charges	385		331		347
Income from continuing operations including noncontrolling interests before income taxes	1,703		1,362		1,394
Income tax expense	653	[6]	540	[6]	542	[6]
Net income attributable to Dominion	1,050		822		852
Amounts attributable to Dominion:
Net income attributable to Dominion	1,050		822		852
Preferred dividends	16		17		17
Balance available for common stock	$ 1,034		$ 805		$ 835

[1] Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

[2] For 2012, includes impairment and other charges of $2.1 billion related to Brayton Point, Kincaid and Kewaunee. See Note 6 for additional information.

[3] In 2012, Dominion's current federal income tax benefit includes a benefit related to the carryback of its current year operating loss, and deferred state income tax benefit reflects the impact of Brayton Point, Kincaid and Kewaunee impairment charges. In 2011, Dominion's federal income tax expense includes a benefit related to its current year operating loss that is expected to be used in future years, and state income tax expense reflects changes in the amount of income apportioned among states, higher tax credits, claims for refunds and previously unrecognized tax benefits due to the expiration of statutes of limitations.

[4] Includes income tax benefit of $27 million, $9 million, and $34 million in 2012, 2011 and 2010, respectively.

[5] Amounts attributable to Dominion's common shareholders.

[6] In 2011, Virginia Power's federal income tax expense includes a benefit related to a portion of its current year operating loss that is expected to be used in future years. Also, in 2011 and 2010, Virginia Power's federal income tax expense reflects the amounts of current year operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

XML

Investments (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Available-for-sale Securities [Line Items]

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)
2012
Marketable equity securities:
U.S.:
Large Cap	$	1,210	$	732	$	—			$	1,942
Other	40		13		—				53
Marketable debt securities:
Corporate debt instruments	295		30		—				325
U.S. Treasury securities and agency debentures	523		19		(2		)		540
State and municipal	248		26		—				274
Other	6		1		—				7
Cost method investments	117		—		—				117
Cash equivalents and other(2)	72		—		—				72
Total	$	2,511	$	821	$	(2	)	(3)	$	3,330
2011
Marketable equity securities:
U.S.:
Large Cap	$	1,152	$	537	$	—			$	1,689
Other	36		10		—				46
Marketable debt securities:
Corporate debt instruments	314		19		(1		)		332
U.S. Treasury securities and agency debentures	437		20		(1		)		456
State and municipal	264		24		—				288
Other	23		1		—				24
Cost method investments	118		—		—				118
Cash equivalents and other(2)	46		—		—				46
Total	$	2,390	$	611	$	(2	)	(3)	$	2,999

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

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

(3) The fair value of securities in an unrealized loss position was $195 million and $164 million at December 31, 2012 and 2011, respectively.

Investments Classified by Contractual Maturity Date

The fair value of Dominion's marketable debt securities held in nuclear decommissioning trust funds at December 31, 2012 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	116
Due after one year through five years	304
Due after five years through ten years	357
Due after ten years	369
Total	$	1,146

Marketable Securities

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

Year Ended December 31,	2012		2011		2010
(millions)
Proceeds from sales	$	1,356	$	1,757	$	1,814	(1)
Realized gains(2)	98		79		111
Realized losses(2)	33		92		63

(1) Does not include $1 billion of proceeds reflected in Dominion's Consolidated Statement of Cash Flows from the sale of temporary investments consisting of time deposits and Treasury Bills, purchased following the sale of substantially all of Dominion's Appalachian E&P operations.

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

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:

Year Ended December 31,	2012			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	26		$	75		$	59
Losses recorded to decommissioning trust regulatory liability	(10		)	(24		)	(21		)
Losses recognized in other comprehensive income (before taxes)	(2		)	(3		)	(3		)
Net impairment losses recognized in earnings	$	14		$	48		$	35

(1) Amounts include other-than-temporary impairment losses for debt securities of $4 million, $6 million and $10 million at December 31, 2012, 2011 and 2010, respectively.

Investments Accounts Under Equity Method of Accounting

Investments that Dominion accounts for under the equity method of accounting are as follows:

Company	Ownership%		Investment Balance				Description
As of December 31,			2012		2011
(millions)
Fowler I Holdings LLC	50	%	$	158	$	166	Wind-powered merchant generation facility
NedPower Mount Storm LLC	50	%	137		146		Wind-powered merchant generation facility
Elwood Energy LLC	50	%	117		108		Natural gas-fired merchant generation peaking facility
Iroquois Gas Transmission System, LP	24.72	%	102		104		Gas transmission system
Blue Racer Midstream LLC	50	%	39		—		Midstream gas and related services
Other(1)	various		5		29
Total			$	558	$	553

Virginia Electric and Power Company

Schedule of Available-for-sale Securities [Line Items]

Available-For-Sale Securities

. Virginia Power's decommissioning trust funds are summarized below:

	Amortized Cost		Total Unrealized Gains (1)		Total Unrealized Losses (1)				Fair Value
(millions)
2012
Marketable equity securities:
U.S.:
Large Cap	$	481	$	298	$	—			$	779
Other	20		7		—				27
Marketable debt securities:
Corporate debt instruments	179		17		—				196
U.S. Treasury securities and agency debentures	231		4		(1		)		234
State and municipal	106		11		—				117
Other	1		—		—				1
Cost method investments	117		—		—				117
Cash equivalents and other(2)	44		—		—				44
Total	$	1,179	$	337	$	(1	)	(3)	$	1,515
2011
Marketable equity securities:
U.S.:
Large Cap	$	460	$	218	$	—			$	678
Other	18		5		—				23
Marketable debt securities:
Corporate debt instruments	204		11		(1		)		214
U.S. Treasury securities and agency debentures	166		4		—				170
State and municipal	114		10		—				124
Other	16		1		(1		)		16
Cost method investments	118		—		—				118
Cash equivalents and other(2)	27		—		—				27
Total	$	1,123	$	249	$	(2	)	(3)	$	1,370

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

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

(3) The fair value of securities in an unrealized loss position was $104 million and $99 million at December 31, 2012 and 2011, respectively

Investments Classified by Contractual Maturity Date

The fair value of Virginia Power's debt securities at December 31, 2012, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	18
Due after one year through five years	156
Due after five years through ten years	217
Due after ten years	157
Total	$	548

Marketable Securities

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

Year Ended December 31,	2012		2011		2010
(millions)
Proceeds from sales	$	626	$	1,030	$	1,192
Realized gains(1)	42		34		52
Realized losses(1)	11		34		23

(1) Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2

Other Than Temporary Impairment Losses On Investment Securities

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

Year Ended December 31,	2012			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	11		$	29		$	25
Losses recorded to decommissioning trust regulatory liability	(10		)	(24		)	(21		)
Losses recorded in other comprehensive income (before taxes)	—			(1		)	(1		)
Net impairment losses recognized in earnings	$	1		$	4		$	3

(1) Amounts include other-than-temporary impairment losses for debt securities of $2 million, $4 million and $6 million at December 31, 2012, 2011 and 2010, respectively

XML

Regulatory Assets and Liabilities (Regulatory Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Regulatory Assets And Liabilities [Line Items]
Unrecovered gas costs	$ 59	[1]	$ 48	[1]
Deferred rate adjustment clause costs	55	[2]	113	[2]
Virginia sales taxes	37	[3]	32	[3]
Plant retirement, regulatory assets-current	25	[4]	27	[4]
Deferred cost of fuel used in electric generation	0	[5]	249	[5]
Derivatives, regulatory assets-current	0	[6]	45	[6]
Other	27		27
Regulatory assets-current	203		541
Unrecognized pension and other postretirement benefit costs	1,210	[7]	887	[7]
Deferred rate adjustment clause costs	173	[7]	107	[7]
Income taxes recoverable through future rates	140	[8]	121	[8]
Derivatives, regulatory assets-non-current	105	[6]	49	[6]
Other postretirement benefit costs	21	[9]	26	[9]
Plant retirement, regulatory assets-non-current	11	[4]	25	[4]
Deferred cost of fuel used in electric generation	0	[5]	122	[5]
Other	57		45
Regulatory assets-non-current	1,717		1,382
Total regulatory assets	1,920		1,923
PIPP, regulatory liabilities-current	100	[10]	58	[10]
Provision for rate proceedings	8	[11]	150	[11]
Other, regulatory assets-non-current	28		35
Regulatory liabilities-current	136		243
Provision for future cost of removal and AROs	985	[12]	901	[12]
Decommissioning trust	501	[13]	399	[13]
Other	28		24
Regulatory liabilities-non-current	1,514		1,324
Total regulatory liabilities	1,650		1,567
Virginia Electric and Power Company
Regulatory Assets And Liabilities [Line Items]
Deferred rate adjustment clause costs	51		113
Virginia sales taxes	37	[3]	32	[3]
Plant retirement, regulatory assets-current	25	[4]	27	[4]
Deferred cost of fuel used in electric generation	0		249
Derivatives, regulatory assets-current	0	[6]	45	[6]
Other	6		13
Regulatory assets-current	119		479
Deferred rate adjustment clause costs	127	[2]	70	[2]
Income taxes recoverable through future rates	110	[8]	100	[8]
Derivatives, regulatory assets-non-current	105	[6]	49	[6]
Plant retirement, regulatory assets-non-current	11	[6]	25	[6]
Deferred cost of fuel used in electric generation	0	[5]	122	[5]
Other	43		33
Regulatory assets-non-current	396		399
Total regulatory assets	515		878
Provision for rate proceedings	7	[11]	150	[11]
Other, regulatory assets-non-current	25		28
Regulatory liabilities-current	32		178
Provision for future cost of removal	763	[12]	687	[12]
Decommissioning trust	501	[13]	399	[13]
Other	21		9
Regulatory liabilities-non-current	1,285		1,095
Total regulatory liabilities	$ 1,317		$ 1,273

[1] Amounts to be recovered through an annual surcharge to reimburse Virginia Power for incremental sales taxes being incurred due to the repeal of the public service company sales tax exemption in Virginia.

[2] Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for more information.

[3] Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power's generation operations. See Note 13 for more information.

[4] As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

[5] Reflects unrecovered gas costs at Dominion's regulated gas operations, which are recovered through quarterly or annual filings with the applicable regulatory authority.

[6] Reflects costs anticipated to be recovered in base rates for certain coal units expected to be retired.

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

[8] Primarily reflects costs recognized in excess of amounts included in regulated rates charged by Dominion's regulated gas operations before rates were updated to reflect a change in accounting method for other postretirement benefit costs.

[9] Under PIPP, eligible customers can receive energy assistance based on their ability to pay. The difference between the customer's total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rider according to East Ohio tariff provisions. See Note 13 for more information regarding PIPP.

[10] Represents unrecognized pension and other postretirement benefit costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain of Dominion's rate-regulated subsidiaries.

[11] Reflects a reserve associated with the Biennial Review Order. See Note 13 for more information.

[12] Rates charged to customers by the Companies' regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.

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

XML

Operating Segments (Narrative) (Details) (USD $)	3 Months Ended										12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012		Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011		Dec. 31, 2012	Dec. 31, 2011		Dec. 31, 2010
Segment Reporting Information [Line Items]
Costs and epenses											$ (11,937,000,000)	$ (11,251,000,000)	[1]	$ (11,543,000,000)	[1]
Loss from discontinued operations, net of tax											(22,000,000)	(25,000,000)	[1]	(258,000,000)	[1]
Discontinued operation tax expense											27,000,000	9,000,000		34,000,000
Asset impairment, net of tax						139,000,000
Operating loss from operations of Kewaunee	892,000,000	(518,000,000)	(617,000,000)	(913,000,000)	[2]	(340,000,000)	(828,000,000)	(733,000,000)	(993,000,000)	[2]	(1,156,000,000)	(2,894,000,000)	[1]	(5,851,000,000)	[1]
Gain (adjustment to gain) on sale of E&P operations											0	0	[1]	2,467,000,000	[1]
Charge for severence pay and other benefits												331,000,000
Charge for severance pay and other benefits, net of tax												202,000,000
DVP
Segment Reporting Information [Line Items]
Restoration costs											87,000,000	96,000,000
Restoration costs net of tax											53,000,000	59,000,000
Charge for severance pay and other benefits, net of tax												67,000,000
Dominion Generation
Segment Reporting Information [Line Items]
Asset impairment											228,000,000
Asset impairment, net of tax											139,000,000
Operating loss from operations of Kewaunee											66,000,000
Operating loss from operations of Kewaunee, net of tax											39,000,000
Impairment of emission allowances											57,000,000
Impairment of emission allowances net of tax											34,000,000
Charge for severance pay and other benefits, net of tax												111,000,000
Peoples
Segment Reporting Information [Line Items]
Loss from discontinued operation												134,000,000
Loss on discontinued operation, net of tax												155,000,000
Dominion Energy
Segment Reporting Information [Line Items]
Charge for severance pay and other benefits, net of tax												24,000,000
Corporate and Other
Segment Reporting Information [Line Items]
Costs and epenses											(1,400,000,000)	(311,000,000)		865,000,000
Net expenses attributable to operating segments											1,400,000,000	340,000,000		1,000,000,000
Kewaunee | Dominion Generation
Segment Reporting Information [Line Items]
Loss from discontinued operations											467,000,000
Loss from discontinued operations, net of tax											303,000,000
State Line and Salem Harbor | Dominion Generation
Segment Reporting Information [Line Items]
Loss from discontinued operations											49,000,000	34,000,000		158,000,000
Loss from discontinued operations, net of tax											22,000,000	25,000,000		103,000,000
Appalachian E & P
Segment Reporting Information [Line Items]
Gain (adjustment to gain) on sale of E&P operations												2,500,000,000
Gain (adjustment to gain) on sale of operations, net of tax												1,400,000,000
Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Costs and epenses											(5,234,000,000)	(5,641,000,000)		(5,578,000,000)
Restoration costs											87,000,000	96,000,000
Restoration costs net of tax			42,000,000								53,000,000	59,000,000
Asset impairment												228,000,000
Asset impairment, net of tax						139,000,000						139,000,000
Operating loss from operations of Kewaunee	(417,000,000)	(746,000,000)	(361,000,000)	(468,000,000)		(55,000,000)	(568,000,000)	(471,000,000)	(511,000,000)		(1,992,000,000)	(1,605,000,000)		(1,641,000,000)
Charge for severance pay and other benefits, net of tax														123,000,000
Virginia Electric and Power Company | DVP
Segment Reporting Information [Line Items]
Charge for severance pay and other benefits, net of tax														63,000,000
Virginia Electric and Power Company | Dominion Generation
Segment Reporting Information [Line Items]
Impairment charges related to State Line												43,000,000
Impairment charges, after tax												26,000,000
Charge for severance pay and other benefits, net of tax														60,000,000
Virginia Electric and Power Company | Corporate and Other
Segment Reporting Information [Line Items]
Costs and epenses											(51,000,000)	(268,000,000)		(153,000,000)
Charge for severence pay and other benefits														202,000,000
Brayton Point Kincaid And Elwood Power Stations | Dominion Generation
Segment Reporting Information [Line Items]
Loss from discontinued operations											1,700,000,000
Loss from discontinued operations, net of tax											$ 1,100,000,000

[1] Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

[2] Revenue and income amounts have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

XML

Employee Benefit Plans (Pension Plan and Other Postretirement Benefit Plan Obligations and Plan Assets and Includes a Statement of the Plans Funded Status) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Changes in fair value of plan assets:
Actual return on plan assets	$ 743	$ 273
Employer contributions	40	38	39
Pension Benefits
Changes in benefit obligation:
Service cost	(116)	(108)	(102)
Interest cost	(268)	(258)	(266)
Other Postretirement Benefits
Changes in benefit obligation:
Service cost	(44)	(48)	(56)
Interest cost	(79)	(94)	(101)
Changes In Benefit Obligation | Pension Benefits
Changes in benefit obligation:
Benefit obligation at beginning of year	4,981	4,490
Service cost	116	108
Interest cost	268	258
Benefits paid	(208)	(215)
Actuarial (gains) losses during the year	967	340
Plan amendments	1	0
Settlements and curtailments	0	0
Medicare Part D reimbursement	0	0
Early Retirement Reimbursement Program	0	0
Benefit obligation at end of year	6,125	4,981
Changes In Benefit Obligation | Other Postretirement Benefits
Changes in benefit obligation:
Benefit obligation at beginning of year	1,493	1,707
Service cost	44	48
Interest cost	79	94
Benefits paid	(88)	(83)
Actuarial (gains) losses during the year	191	(210)
Plan amendments	1	(70)
Settlements and curtailments	(6)	(1)
Medicare Part D reimbursement	5	5
Early Retirement Reimbursement Program	0	3
Benefit obligation at end of year	1,719	1,493
Changes In Fair Value Of Plan Assets | Pension Benefits
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	5,145	5,106
Actual return on plan assets	611	247
Employer contributions	5	7
Benefits paid	(208)	(215)
Fair value of plan assets at end of year	5,553	5,145
Funded status at end of year	(572)	164
Changes In Fair Value Of Plan Assets | Other Postretirement Benefits
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	1,042	1,031
Actual return on plan assets	132	26
Employer contributions	16	19
Benefits paid	(34)	(34)
Fair value of plan assets at end of year	1,156	1,042
Funded status at end of year	(563)	(451)
Level 1 | Pension Benefits
Changes in fair value of plan assets:
Noncurrent pension and other postretirement benefit assets	701	677
Other current liabilities	(2)	(3)
Noncurrent pension and other postretirement benefit liabilities	(1,271)	(510)
Net amount recognized	(572)	164
Level 1 | Other Postretirement Benefits
Changes in fair value of plan assets:
Noncurrent pension and other postretirement benefit assets	1	4
Other current liabilities	(4)	(3)
Noncurrent pension and other postretirement benefit liabilities	(560)	(452)
Net amount recognized	$ (563)	$ (451)
Level 2 | Pension Benefits
Changes in fair value of plan assets:
Discount rate	4.40%	5.50%
Weighted average rate of increase for compensation	4.21%	4.21%
Level 2 | Other Postretirement Benefits
Changes in fair value of plan assets:
Discount rate	4.40%	5.50%
Weighted average rate of increase for compensation	4.22%	4.22%

XML

Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 248		$ 102
Customer receivables	1,621		1,780
Other receivables	96		255
Inventories:
Materials and supplies	684		641
Fossil fuel	467		541
Gas stored	108		166
Derivative assets	518		705
Regulatory assets	203		541
Prepayments	326		262
Deferred income taxes	573		9
Other	296		428
Total current assets	5,140		5,430
Investments
Nuclear decommissioning trust funds	3,330		2,999
Investment in equity method affiliates	558		553
Restricted cash equivalents	33		141
Other	270		292
Total investments	4,191		3,985
Property, Plant and Equipment
Property, plant and equipment	43,364		42,033
Property, plant and equipment, VIE	957		957
Accumulated depreciation, depletion and amortization	(13,548)		(13,320)
Total property, plant and equipment, net	30,773		29,670
Deferred Charges and Other Assets
Goodwill	3,130	[1]	3,141	[1]
Pension and other postretirement benefit assets	702		681
Intangible assets	536		637
Regulatory assets	1,717		1,382
Other	649		688
Total deferred charges and other assets	6,734		6,529
Total assets	46,838		45,614
Current Liabilities
Securities due within one year	1,363		1,479
Securities due within one year, VIE	860		0
Short-term debt	2,412		1,814
Accounts payable	1,137		1,250
Accrued interest, payroll and taxes	636		648
Derivative liabilities	510		951
Regulatory liabilities	136		243
Other	709		577
Total current liabilities	7,763		6,962
Long-Term Debt
Long-term debt	15,478		14,785
Long-term debt, VIE	0		890
Junior subordinated notes	1,373		1,719
Total long-term debt	16,851		17,394
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	5,800		5,216
Asset retirement obligations	1,641		1,383
Pension and other postretirement benefit liabilities	1,831		962
Regulatory liabilities	1,514		1,324
Other	556		613
Total deferred credits and other liabilities	11,342		9,498
Total liabilities	35,956		33,854
Subsidiary Preferred Stock Not Subject To Mandatory Redemption	257		257
Equity
Common stock-no par	5,493.0	[2]	5,180.0	[2]
Other paid-in capital	162		179
Retained earnings	5,790		6,697
Accumulated other comprehensive loss	(877)		(610)
Total common shareholders' equity	10,568		11,446
Noncontrolling interest	57		57
Total equity	10,625		11,503
Total liabilities and equity	46,838		45,614
Virginia Electric and Power Company
Current Assets
Cash and cash equivalents	28		29
Customer receivables	849		892
Other receivables	51		145
Inventories:
Materials and supplies	385		359
Fossil fuel	404		438
Regulatory assets	119		479
Prepayments	23		41
Deferred income taxes	92		0
Other	30		53
Total current assets	1,981		2,436
Investments
Nuclear decommissioning trust funds	1,515		1,370
Other	14		36
Total investments	1,529		1,406
Property, Plant and Equipment
Property, plant and equipment	30,631		28,626
Accumulated depreciation, depletion and amortization	(10,014)		(9,615)
Total property, plant and equipment, net	20,617		19,011
Deferred Charges and Other Assets
Intangible assets	181		183
Regulatory assets	396		399
Other	107		109
Total deferred charges and other assets	684		691
Total assets	24,811		23,544
Current Liabilities
Securities due within one year	418		616
Short-term debt	992		894
Accounts payable	430		405
Payables to affiliates	67		108
Affiliated current borrowings	435		187
Accrued interest, payroll and taxes	204		226
Derivative liabilities	33		135
Customer deposits	100		106
Regulatory liabilities	32		178
Deferred income taxes	0		91
Other	296		175
Total current liabilities	3,007		3,121
Long-Term Debt
Total long-term debt	6,251		6,246
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	3,879		3,180
Asset retirement obligations	705		624
Regulatory liabilities	1,285		1,095
Other	194		271
Total deferred credits and other liabilities	6,063		5,170
Total liabilities	15,321		14,537
Commitments and Contingencies (see Note 22)
Subsidiary Preferred Stock Not Subject To Mandatory Redemption	257		257
Equity
Common stock-no par	5,738.0	[3]	5,738.0	[3]
Other paid-in capital	1,113		1,111
Retained earnings	2,357		1,882
Accumulated other comprehensive loss	25		19
Total common shareholders' equity	9,233		8,750
Total equity	9,233		8,750
Total liabilities and equity	$ 24,811		$ 23,544

[1] Goodwill amounts do not contain any accumulated impairment losses.

[2] 1 billion shares authorized; 576 million shares and 570 million shares outstanding at December 31, 2012 and 2011, respectively.

[3] 500,000 shares shares authorized at December 31, 2012 and 2011; 274,723 shares outstanding at December 31, 2012 and 2011.

XML

Goodwill and Intangible Assets (Annual Amortization Expense of Intangible Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
2013	$ 65
2014	56
2015	43
2016	37
2017	25
Virginia Electric and Power Company
Finite-Lived Intangible Assets [Line Items]
2013	20
2014	18
2015	12
2016	8
2017	$ 5

XML

Quarterly Financial and Common Stock Data (Unaudited) (Quarterly Financial and Common Stock Data) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Operating Revenue	$ 3,167		$ 3,411		$ 3,053		$ 3,462	[1]	$ 3,129		$ 3,745		$ 3,288		$ 3,983	[1]	$ 13,093		$ 14,145	[2]	$ 14,927	[2]
Income (loss) from operations	(892)		518		617		913	[1]	340		828		733		993	[1]	1,156		2,894	[2]	5,851	[2]
Net income (loss) including noncontrolling interests	(652)		215		265		501	[1]	207		396		340		483	[1]	329		1,426	[2]	2,825	[2]
Income from continuing operations	(659)	[3]	214	[3]	276	[3]	493	[1],[3]	200	[3]	388	[3]	341	[3]	504	[1],[3]	324	[3]	1,433	[2],[3]	3,066	[2]
Income (loss) from discontinued operations	0	[3]	(5)	[3]	(18)	[3]	1	[1],[3]	1	[3]	4	[3]	(5)	[3]	(25)	[1],[3]	(22)	[3]	(25)	[3]
Net income attributable to Dominion	(659)		209		258		494	[1]	201		392		336		479	[1]	302		1,408	[2]	2,808	[2]
Income from continuing operations - basic (in dollars per share)	$ (1.15)	[3]	$ 0.37	[3]	$ 0.48	[3]	$ 0.86	[1],[3]	$ 0.35	[3]	$ 0.68	[3]	$ 0.59	[3]	$ 0.87	[1],[3]	$ 0.57	[3]	$ 2.50	[2],[3]	$ 5.21	[2]
Income (loss) from discontinued operations - basic (in dollars per share)			$ (0.01)	[3]	$ (0.03)	[3]	$ 0.00	[1],[3]	$ 0.00	[3]	$ 0.01	[3]	$ (0.01)	[3]	$ (0.04)	[1],[3]	$ (0.04)		$ (0.04)	[2],[3]	$ (0.44)	[2]
Net income attributable to Dominion (in dollars per share)	$ (1.15)		$ 0.36		$ 0.45		$ 0.86	[1]	$ 0.35		$ 0.69		$ 0.58		$ 0.83	[1]	$ 0.53		$ 2.46	[2]	$ 4.77	[2]
Income from continuing operations - diluted (in dollars per share)	$ (1.15)	[3]	$ 0.37	[3]	$ 0.48	[3]	$ 0.86	[1],[3]	$ 0.35	[3]	$ 0.68	[3]	$ 0.59	[3]	$ 0.86	[1],[3]	$ 0.57	[3]	$ 2.49	[2],[3]	$ 5.20	[2]
Income (loss) from discontinued operations - diluted (in dollars per share)			$ (0.01)	[3]	$ (0.03)	[3]	$ 0.00	[1],[3]	$ 0.00	[3]	$ 0.01	[3]	$ (0.01)	[3]	$ (0.04)	[1],[3]	$ (0.04)		$ (0.04)	[2],[3]	$ (0.44)	[2]
Net income attributable to Dominion - diluted (in dollars per share)	$ (1.15)		$ 0.36		$ 0.45		$ 0.86	[1]	$ 0.35		$ 0.69		$ 0.58		$ 0.82	[1]	$ 0.53		$ 2.45	[2]	$ 4.76	[2]
Dividends declared per common share	$ 0.5275		$ 0.5275		$ 0.5275		$ 0.5275	[1]	$ 0.4925		$ 0.4925		$ 0.4925		$ 0.4925	[1]	$ 2.11		$ 1.97	[2]	$ 1.83	[2]
Virginia Electric and Power Company
Operating Revenue	1,630		2,086		1,756		1,754		1,555		2,177		1,757		1,757		7,226		7,246		7,219
Income (loss) from operations	417		746		361		468		55		568		471		511		1,992		1,605		1,641
Net income attributable to Dominion	220		415		172		243		6		297		241		278		1,050		822		852
Balance available for common stock	$ 216		$ 411		$ 168		$ 239		$ 1		$ 293		$ 237		$ 274		$ 1,034		$ 805		$ 835
Maximum
Share Price	$ 53.89		$ 55.62		$ 54.69		$ 53.68		$ 53.59		$ 51.44		$ 48.55		$ 46.56		$ 53.89		$ 53.59
Common stock market value (high)																	$ 55.62		$ 53.59
Minimum
Share Price	$ 48.94		$ 52.15		$ 49.87		$ 48.67		$ 48.21		$ 44.5		$ 43.27		$ 42.06		$ 48.94		$ 48.21
Common stock market value (low)																	$ 48.87		$ 42.06

[1] Revenue and income amounts have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

[2] Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

[3] Amounts attributable to Dominion's common shareholders.

XML

Significant Accounting Policies (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounting Policy [Line Items]
Accrued unbilled revenue	$ 411	$ 423
Percentage of fuel currently subject to deferred fuel accounting	83.00%
Interest income	8
Reduction in interest expense	3	7	18
Reduction in penalties (less than $1 million)	1	1	1
Income Tax Interest Income		12
Accrued interest receivable	5	48
Interest and penalties payable	10	10
Income tax examination, penalties accrued	1	1
Accounts payable for checks outstanding	53	75
Margin assets	212	319
Margin liabilities	4	66
Capitalized interest costs	91	85	102
Ceiling test impairment charge			21
Ceiling test impairment charge net of tax			13
Inventory under LIFO method	24	48
Amount exceeded on LIFO basis	69	86
Virginia Electric and Power Company
Accounting Policy [Line Items]
Accrued unbilled revenue	348	360
Income Tax Interest Income	12
Accrued interest receivable	17
Prepaid federal and state income taxes	10
Noncurrent federal and state income taxes payable	36	110
Current taxes payable	0	91
Accounts payable for checks outstanding	30	40
Margin assets	18	41
Capitalized interest costs	31	31	61
AFUDC related to projects	37	20	13
Federal | Virginia Electric and Power Company
Accounting Policy [Line Items]
Prepaid federal and state income taxes		18
State | Virginia Electric and Power Company
Accounting Policy [Line Items]
Current taxes payable		$ 34

XML

Asset Retirement Obligations (Changes to AROs) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
AROs, Beginning balance	$ 1,398	[1]	$ 1,591	[1]
Obligations incurred during the period	24		16
Obligations settled during the period	(13)		(16)
Revisions in estimated cash flows	242	[2]	(277)	[3]
Accretion	77		84
Other	(23)
AROs , Ending balance	1,705	[1]	1,398	[1]
Other current liabilities	64		15		14
Virginia Electric and Power Company
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
AROs, Beginning balance	625	[4]	672	[4]
Obligations incurred during the period	18		10
Obligations settled during the period	(1)		(3)
Revisions in estimated cash flows	41	[5]	(90)	[3]
Accretion	34		36
Other	(12)
AROs , Ending balance	705		625	[4]
Asset Retirement Obligation, Current			$ 1		$ 3

[1] Includes $14 million, $15 million and $64 million reported in other current liabilities at December 31, 2010, 2011, and 2012, respectively.

[2] Primarily reflects the accelerated timing of the decommissioning of Kewaunee to begin in 2013.

[3] Primarily reflects the effect of lower anticipated costs due to the expected future recovery from the DOE of certain spent fuel storage costs.

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

[5] Primarily reflects the effect of higher anticipated nuclear decommissioning costs.

XML

Operating Segments

12 Months Ended

Dec. 31, 2012

Segment Reporting Information, Revenue for Reportable Segment [Abstract]

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 and storage	X
	LNG import and storage	X
	Producer services	X

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

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

The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of the operations that are expected to be or are currently discontinued, which are discussed in Note 3. In addition, Corporate and Other includes specific items attributable to Dominion's operating segments that are not included in profit measures evaluated by executive management in assessing the segments' performance or allocating resources among the segments.

DOMINION

In 2012, Dominion reported after-tax net expense of $1.4 billion for specific items in the Corporate and Other segment, with $1.4 billion of these net expenses attributable to its operating segments.

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

• A $1.7 billion ($1.1 billion after-tax) net loss from operations, including an impairment charge, of Brayton Point, Kincaid and Elwood, attributable to Dominion Generation. Dominion announced its intention to pursue the sale of these two merchant power stations and equity method investment in the third quarter of 2012;

• A $467 million ($303 million after-tax) net loss, including impairment charges, primarily resulting from management's decision to cease operations and begin decommissioning Kewaunee in 2013, attributable to Dominion Generation;

• An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP; and

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

In 2011, Dominion reported after-tax net expense of $311 million for specific items in the Corporate and Other segment, with $340 million of these net expenses attributable to its operating segments.

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

• A $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units, attributable to Dominion Generation;

• A $96 million ($59 million after-tax) charge reflecting restoration costs associated with damage caused by Hurricane Irene, primarily attributable to DVP;

• A $66 million ($39 million after-tax) loss from the operations of Kewaunee, 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 $34 million ($25 million after-tax) loss from discontinued operations of State Line and Salem Harbor which were sold in 2012, attributable to Dominion Generation.

In 2010, Dominion reported after-tax net benefits of $865 million for specific items in the Corporate and Other segment, with $1.0 billion of these net benefits attributable to its operating segments.

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 $331 million ($202 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 ($111 million after-tax);

• A $158 million ($103 million after-tax) loss from the discontinued operations of State Line and Salem Harbor; and

• A $134 million ($155 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.

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

Year Ended December 31,	DVP		Dominion Generation(1)		Dominion Energy		Corporate and Other(1)			Adjustments & Eliminations			Consolidated Total
(millions)
2012
Total revenue from external customers	$	3,385	$	6,517	$	1,813	$	307		$	1,071		$	13,093
Intersegment revenue	112		333		930		608			(1,983		)	—
Total operating revenue	3,497		6,850		2,743		915			(912		)	13,093
Depreciation, depletion and amortization	402		500		216		68			—			1,186
Equity in earnings of equity method investees	—		3		23		(1		)	—			25
Interest income	9		57		30		71			(106		)	61
Interest and related charges	187		208		47		546			(106		)	882
Income taxes	351		479		352		(1,036		)	—			146
Loss from discontinued operations, net of tax	—		—		—		(22		)	—			(22		)
Net income (loss) attributable to Dominion	559		874		551		(1,682		)	—			302
Investment in equity method investees	1		414		141		2			—			558
Capital expenditures	1,158		1,615		1,350		22			—			4,145
Total assets (billions)	12.1		21.2		11.2		12.6			(10.3		)	46.8
2011
Total revenue from external customers	$	3,663	$	7,080	$	2,044	$	55		$	1,303		$	14,145
Intersegment revenue	173		355		1,077		596			(2,201		)	—
Total operating revenue	3,836		7,435		3,121		651			(898		)	14,145
Depreciation, depletion and amortization	374		457		207		28			—			1,066
Equity in earnings of equity method investees	—		3		23		9			—			35
Interest income	22		54		27		70			(106		)	67
Interest and related charges	185		217		57		514			(106		)	867
Income taxes	318		583		323		(470		)	—			754
Loss from discontinued operations, net of tax	—		—		—		(25		)	—			(25		)
Net income (loss) attributable to Dominion	501		968		521		(582		)	—			1,408
Investment in equity method investees	8		415		104		26			—			553
Capital expenditures	1,091		1,593		907		61			—			3,652
Total assets (billions)	11.5		22.1		10.6		11.4			(10.0		)	45.6
2010
Total revenue from external customers	$	3,613	$	7,735	$	2,335	$	19		$	1,225		$	14,927
Intersegment revenue	207		413		1,166		750			(2,536		)	—
Total operating revenue	3,820		8,148		3,501		769			(1,311		)	14,927
Depreciation, depletion and amortization	353		443		210		29			—			1,035
Equity in earnings of equity method investees	—		11		21		10			—			42
Interest income	12		45		12		92			(90		)	71
Interest and related charges	158		179		85		494			(90		)	826
Income taxes	277		756		302		777			—			2,112
Loss from discontinued operations, net of tax	—		—		—		(258		)	—			(258		)
Net income attributable to Dominion	448		1,263		475		622			—			2,808
Capital expenditures	1,038		1,742		613		29			—			3,422

(1) Segment information has been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

At December 31, 2012, 2011, and 2010, none of Dominion's long-lived assets and no significant percentage of its operating revenues were associated with international operations.

VIRGINIA POWER

The majority of Virginia Power's revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power's DVP and Dominion Generation segments.

In 2012, Virginia Power reported after-tax net expenses of $51 million for specific items attributable to its operating segments in the Corporate and Other segment.

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

•An $87 million ($53 million after-tax) charge reflecting restoration costs associated with damage caused by severe storms, attributable to DVP.

In 2011, Virginia Power reported after-tax net expenses of $268 million 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 $228 million ($139 million after-tax) charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired generating units, attributable to Dominion Generation;

• A $96 million ($59 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.

In 2010, Virginia Power reported after-tax net expenses of $153 million for specific items attributable to its operating segments in the Corporate and Other segment.

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 Virginia Power's operations:

Year Ended December 31,	DVP		Dominion Generation		Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2012
Operating revenue	$	1,847	$	5,379	$	—		$	—		$	7,226
Depreciation and amortization	392		390		—			—			782
Interest income	1		7		—			—			8
Interest and related charges	186		199		—			—			385
Income taxes	277		403		(27		)	—			653
Net income (loss)	448		653		(51		)	—			1,050
Capital expenditures	1,142		1,146		—			—			2,288
Total assets (billions)	11.4		14.8		—			(1.4		)	24.8
2011
Operating revenue	$	1,793	$	5,546	$	(93	)	$	—		$	7,246
Depreciation and amortization	368		350		—			—			718
Interest income	10		8		—			—			18
Interest and related charges	182		199		(50		)	—			331
Income taxes	265		447		(172		)	—			540
Net income (loss)	426		664		(268		)	—			822
Capital expenditures	1,081		1,009		—			—			2,090
Total assets (billions)	10.7		14.3		—			(1.5		)	23.5
2010
Operating revenue	$	1,680	$	5,546	$	(7	)	$	—		$	7,219
Depreciation and amortization	344		327		—			—			671
Interest income	11		4		—			—			15
Interest and related charges	158		189		—			—			347
Income taxes	228		385		(71		)	—			542
Net income (loss)	377		630		(155		)	—			852
Capital expenditures	1,035		1,199		—			—			2,234

XML

Commitments and Contingencies (Subsidiary Guarantees) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 4,206
Value	915	[1]
Debt
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	363	[2]
Value	363	[1],[2]
Commodity transactions
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	2,939	[3]
Value	377	[1],[3]
Nuclear obligations
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	231	[4]
Value	77	[1],[4]
Other
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	673	[5]
Value	98	[1],[5]
Millstone | Nuclear obligations
Guarantor Obligations [Line Items]
Stated Limit	150
Kewaunee | Nuclear obligations
Guarantor Obligations [Line Items]
Stated Limit	$ 60

[1] Represents the estimated portion of the guarantee's stated limit that is utilized as of December 31, 2012 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

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

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

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

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

XML

Income Taxes (Income Tax Expense for Continuing Operations Including Noncontrolling Interests) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Current:
Federal	$ (117)	[1]	$ 3	[1]	$ 894	[1]
State	80	[1]	9	[1]	309	[1]
Total current expense (benefit)	(37)	[1]	12	[1]	1,203	[1]
Deferred:
Federal	214	[1]	694	[1]	818	[1]
State	(30)	[1]	50	[1]	93	[1]
Total deferred expense	184	[1]	744	[1]	911	[1]
Amortization of deferred investment tax credits	(1)	[1]	(2)	[1]	(2)	[1]
Total income tax expense	146	[1]	754	[1],[2]	2,112	[1],[2]
Virginia Electric and Power Company
Current:
Federal	70	[3]	(35)	[3]	(78)	[3]
State	81	[3]	79	[3]	10	[3]
Total current expense (benefit)	151	[3]	44	[3]	(68)	[3]
Deferred:
Federal	482	[3]	484	[3]	537	[3]
State	21	[3]	13	[3]	74	[3]
Total deferred expense	503	[3]	497	[3]	611	[3]
Amortization of deferred investment tax credits	(1)	[3]	(1)	[3]	(1)	[3]
Total income tax expense	$ 653	[3]	$ 540	[3]	$ 542	[3]

[1] In 2012, Dominion's current federal income tax benefit includes a benefit related to the carryback of its current year operating loss, and deferred state income tax benefit reflects the impact of Brayton Point, Kincaid and Kewaunee impairment charges. In 2011, Dominion's federal income tax expense includes a benefit related to its current year operating loss that is expected to be used in future years, and state income tax expense reflects changes in the amount of income apportioned among states, higher tax credits, claims for refunds and previously unrecognized tax benefits due to the expiration of statutes of limitations.

[2] Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

[3] In 2011, Virginia Power's federal income tax expense includes a benefit related to a portion of its current year operating loss that is expected to be used in future years. Also, in 2011 and 2010, Virginia Power's federal income tax expense reflects the amounts of current year operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

XML

Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETSAND LIABILITIES

Regulatory assets and liabilities include the following:

At December 31,	2012		2011
(millions)
Dominion
Regulatory assets:
Unrecovered gas costs(1)	$	59	$	48
Deferred rate adjustment clause costs(2)	55		113
Virginia sales taxes(3)	37		32
Plant retirement(4)	25		27
Deferred cost of fuel used in electric generation(5)	—		249
Derivatives(6)	—		45
Other	27		27
Regulatory assets-current	203		541
Unrecognized pension and other postretirement benefit costs(7)	1,210		887
Deferred rate adjustment clause costs(2)	173		107
Income taxes recoverable through future rates(8)	140		121
Derivatives(6)	105		49
Other postretirement benefit costs(9)	21		26
Plant retirement(4)	11		25
Deferred cost of fuel used in electric generation(5)	—		122
Other	57		45
Regulatory assets-non-current	1,717		1,382
Total regulatory assets	$	1,920	$	1,923
Regulatory liabilities:
PIPP(10)	$	100	$	58
Provision for rate proceedings(11)	8		150
Other	28		35
Regulatory liabilities-current	136		243
Provision for future cost of removal and AROs(12)	985		901
Decommissioning trust(13)	501		399
Other	28		24
Regulatory liabilities-non-current	1,514		1,324
Total regulatory liabilities	$	1,650	$	1,567
Virginia Power
Regulatory assets:
Deferred rate adjustment clause costs(2)	$	51	$	113
Virginia sales taxes(3)	37		32
Plant retirement(4)	25		27
Deferred cost of fuel used in electric generation(5)	—		249
Derivatives(6)	—		45
Other	6		13
Regulatory assets-current	119		479
Deferred rate adjustment clause costs(2)	127		70
Income taxes recoverable through future rates(8)	110		100
Derivatives(6)	105		49
Plant retirement(4)	11		25
Deferred cost of fuel used in electric generation(5)	—		122
Other	43		33
Regulatory assets-non-current	396		399
Total regulatory assets	$	515	$	878
Regulatory liabilities:
Provision for rate proceedings(11)	$	7	$	150
Other	25		28
Regulatory liabilities-current	32		178

Provision for future cost of removal(12)	763		687
Decommissioning trust(13)	501		399
Other	21		9
Regulatory liabilities-non-current	1,285		1,095
Total regulatory liabilities	$	1,317	$	1,273

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

(2) Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for more information.

(3) Amounts to be recovered through an annual surcharge to reimburse Virginia Power for incremental sales taxes being incurred due to the repeal of the public service company sales tax exemption in Virginia.

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

(5) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power's generation operations. See Note 13 for more information.

(6) As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

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

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

(9) Primarily reflects costs recognized in excess of amounts included in regulated rates charged by Dominion's regulated gas operations before rates were updated to reflect a change in accounting method for other postretirement benefit costs.

(10) Under PIPP, eligible customers can receive energy assistance based on their ability to pay. The difference between the customer's total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rider according to East Ohio tariff provisions. See Note 13 for more information regarding PIPP.

(11) Reflects a reserve associated with the Biennial Review Order. See Note 13 for more information.

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

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

At December 31, 2012, approximately $319 million of Dominion's and $240 million of Virginia Power's regulatory assets represented past expenditures on which they do not currently earn a return. These expenditures are expected to be recovered within the next two years.

XML

Quarterly Financial and Common Stock Data (Unaudited)

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Information [Abstract]

Quarterly Financial and Common Stock Data (Unaudited)

QUARTERLY FINANCIALAND COMMON STOCK DATA (UNAUDITED)

A summary of Dominion's and Virginia Power's quarterly results of operations for the years ended December 31, 2012 and 2011 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

DOMINION

	First Quarter(2)			Second Quarter			Third Quarter			Fourth Quarter			Full Year
(millions, except per share amounts)
2012
Operating revenue	$	3,462		$	3,053		$	3,411		$	3,167		$	13,093
Income (loss) from operations	913			617			518			(892		)	1,156
Net income (loss) including noncontrolling interests	501			265			215			(652		)	329
Income (loss) from continuing operations(1)	493			276			214			(659		)	324
Income (loss) from discontinued operations(1)	1			(18		)	(5		)	—			(22		)
Net income (loss) attributable to Dominion	494			258			209			(659		)	302
Basic EPS:
Income (loss) from continuing operations(1)	0.86			0.48			0.37			(1.15		)	0.57
Income (loss) from discontinued operations(1)	—			(0.03		)	(0.01		)	—			(0.04		)
Net income (loss) attributable to Dominion	0.86			0.45			0.36			(1.15		)	0.53
Diluted EPS:
Income (loss) from continuing operations(1)	0.86			0.48			0.37			(1.15		)	0.57
Loss from discontinued operations(1)	—			(0.03		)	(0.01		)	—			(0.04		)
Net income (loss) attributable to Dominion	0.86			0.45			0.36			(1.15		)	0.53
Dividends declared per share	0.5275			0.5275			0.5275			0.5275			2.11
Common stock prices (intraday high-low)	$53.68  - 48.87			$54.69  - 49.87			$55.62 - 52.15			$53.89  - 48.94			$55.62  - 48.87
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Full Year
2011(2)
Operating revenue	$	3,983		$	3,288		$	3,745		$	3,129		$	14,145
Income from operations	993			733			828			340			2,894
Net income including noncontrolling interests	483			340			396			207			1,426
Income from continuing operations(1)	504			341			388			200			1,433
Income (loss) from discontinued operations(1)	(25		)	(5		)	4			1			(25		)
Net income attributable to Dominion	479			336			392			201			1,408
Basic EPS:
Income from continuing operations(1)	0.87			0.59			0.68			0.35			2.50
Income (loss) from discontinued operations(1)	(0.04		)	(0.01		)	0.01			—			(0.04		)
Net income attributable to Dominion	0.83			0.58			0.69			0.35			2.46
Diluted EPS:
Income from continuing operations(1)	0.86			0.59			0.68			0.35			2.49
Income (loss) from discontinued operations(1)	(0.04		)	(0.01		)	0.01			—			(0.04		)
Net income attributable to Dominion	0.82			0.58			0.69			0.35			2.45
Dividends declared per share	0.4925			0.4925			0.4925			0.4925			1.97
Common stock prices (intraday high-low)	$46.56  - 42.06			$48.55  - 43.27			$51.44 - 44.50			$53.59  - 48.21			$53.59  - 42.06

(1) Amounts attributable to Dominion's common shareholders.

(2) Revenue and income amounts have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

Dominion's 2012 results include the impact of the following significant items:

• Fourth quarter results include a $1.0 billion after-tax impairment charge to write down Brayton Point’s and Kincaid's long-lived assets to their estimated fair value.

• Third quarter results include a $281 million after-tax net loss, including impairment charges, primarily resulting from management's decision to cease operations and begin decommissioning Kewaunee in 2013.

Dominion's 2011 results include the impact of the following significant item:

• Fourth quarter results include a $139 million after-tax charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain utility coal-fired generating units.

VIRGINIA POWER

Virginia Power's quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
(millions)
2012
Operating revenue	$	1,754	$	1,756	$	2,086	$	1,630	$	7,226
Income from operations	468		361		746		417		1,992
Net income	243		172		415		220		1,050
Balance available for common stock	239		168		411		216		1,034
2011
Operating revenue	$	1,757	$	1,757	$	2,177	$	1,555	$	7,246
Income from operations	511		471		568		55		1,605
Net income	278		241		297		6		822
Balance available for common stock	274		237		293		1		805

Virginia Power's 2012 results include the impact of the following significant item:

• Second quarter results include a $42 million after-tax charge reflecting restoration costs associated with damage caused by late June summer storms.

Virginia Power's 2011 results include the impact of the following significant item:

• Fourth quarter results include a $139 million after-tax charge reflecting plant balances that are not expected to be recovered in future periods due to the anticipated retirement of certain coal-fired power stations.

XML

Asset Retirement Obligations (Narrative) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligations [Line Items]
Fair value, primarily of equity and debt securities	$ 3,300,000,000	$ 3,000,000,000
Nuclear decommissioning trust funds	3,330,000,000	2,999,000,000
Virginia Electric and Power Company
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds	$ 1,515,000,000	$ 1,370,000,000

XML

Commitments and Contingencies (Environmental Matters) (Narrative) (Details) (USD $)	3 Months Ended	9 Months Ended	12 Months Ended	3 Months Ended			1 Months Ended
	Mar. 31, 2013	Sep. 30, 2012	Dec. 31, 2012	Mar. 31, 2013 Minimum	Mar. 31, 2013 Maximum	Sep. 30, 2012 Clean Air Act	Dec. 31, 2012 Virginia Electric and Power Company
Loss Contingencies [Line Items]
Charge reflecting plant balances not expected to be recovered							$ 228,000,000
Charge reflecting plant balances not expected to be recovered, net of tax							139,000,000
Maximum civil penalties per day	37,500			25,000	37,500
Estimate of possible loss						13,000,000
Total cost to install cooling towers		550,000,000
Percent further emission reduction goals in participating state power plant CO2 emissions	10.00%
Acquisition cost of Rggi allowances			$ 38,000,000

XML

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

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

The Companies have also identified, but not recognized, AROs related to retirement of Dominion's LNG facility, Dominion's gas storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power's hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in the Companies' generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 2011 and 2012 were as follows:

	Amount
(millions)
Dominion
AROs at December 31, 2010(1)	$	1,591
Obligations incurred during the period	16
Obligations settled during the period	(16		)
Revisions in estimated cash flows(2)	(277		)
Accretion	84
AROs at December 31, 2011(1)	$	1,398
Obligations incurred during the period	24
Obligations settled during the period	(13		)
Revisions in estimated cash flows(3)	242
Accretion	77
Other	(23		)
AROs at December 31, 2012(1)	$	1,705
Virginia Power
AROs at December 31, 2010(4)	$	672
Obligations incurred during the period	10
Obligations settled during the period	(3		)
Revisions in estimated cash flows(2)	(90		)
Accretion	36
AROs at December 31, 2011(4)	$	625
Obligations incurred during the period	18
Obligations settled during the period	(1		)
Revisions in estimated cash flows(5)	41
Accretion	34
Other	(12		)
AROs at December 31, 2012	$	705

(1) Includes $14 million, $15 million and $64 million reported in other current liabilities at December 31, 2010, 2011, and 2012, respectively.

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

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

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

(5) Primarily reflects the effect of higher anticipated nuclear decommissioning costs.

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

XML

Income Taxes (Unrecognized Tax Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1	$ 347	$ 307	$ 291
Increases-prior period positions	28	127	34
Decreases-prior period positions	(106)	(119)	(75)
Increases-current period positions	43	64	61
Decreases-current period positions	0	(21)	0
Settlements with tax authorities	(4)	0	0
Expiration of statutes of limitation	(15)	(11)	(4)
Balance at December 31	293	347	307
Virginia Electric and Power Company
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1	114	117	121
Increases-prior period positions	4	22	4
Decreases-prior period positions	(80)	(51)	(33)
Increases-current period positions	24	47	25
Decreases-current period positions	0	(21)	0
Settlements with tax authorities	(4)	0	0
Expiration of statutes of limitation	(1)	0	0
Balance at December 31	$ 57	$ 114	$ 117

XML

Shareholders' Equity (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended	12 Months Ended											12 Months Ended												1 Months Ended			12 Months Ended	1 Months Ended				12 Months Ended
	Jan. 31, 2012 Agreement	Dec. 31, 2012 Performance_Metric		Dec. 31, 2011		Dec. 31, 2010	Dec. 31, 2012 Virginia Electric and Power Company		Dec. 31, 2010 Virginia Electric and Power Company	Dec. 31, 2011 Virginia Electric and Power Company		Dec. 31, 2012 Stock-Based Awards	Dec. 31, 2012 Restricted Stock	Dec. 31, 2011 Restricted Stock	Dec. 31, 2010 Restricted Stock	Dec. 31, 2010 Restricted Stock Non-Officer Employees	Dec. 31, 2012 Goal-Based Stock	Dec. 31, 2011 Goal-Based Stock Performance_Metric	Dec. 31, 2010 Goal-Based Stock	Dec. 31, 2010 Goal-Based Stock Non-Officer Employees	Dec. 31, 2012 Goal-Based Stock Officer	Dec. 31, 2011 Goal-Based Stock Officer	Dec. 31, 2010 Goal-Based Stock Officer	Dec. 31, 2007 Cash-Based Performance Grant	Feb. 28, 2012 February 2010 Awards	Dec. 31, 2011 February 2010 Awards	Feb. 28, 2010 February 2010 Awards	Dec. 31, 2011 February 2010 Awards	Feb. 28, 2011 April 2009	Dec. 31, 2010 April 2009	Apr. 30, 2009 April 2009	Dec. 31, 2012 February 2011 Awards	Dec. 31, 2012 February 2011 Awards	Dec. 31, 2012 February 2012 Awards	Dec. 31, 2012 Dominion Direct, employee savings plans
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock shares issued		6,400,000							33,013																										5,300,000
Cash proceeds		$ 265		$ 38		$ 74			$ 1,000
Number of Sales Agency Agreements	4
Expected issuance of common stock in 2012 through employee savings plans, direct stock purchase and dividend reinvestment plans, and other employee and director benefit plans		318
Common Securities Amount		5,493.0	[1]	5,180.0	[1]		5,738.0	[2]	1,000.0	5,738.0	[2]
Shares reserved and available for issuance		48,000,000
Common stock repurchased				13,000,000
Payment for repurchase of common stock		0		601		900
Average Price Per Share Of Shares Repurchased				$ 46.37
Shares were available for future grants												32,000,000
Compensation cost related to stock-based compensation		25		39		40
Tax benefit from stock awards and stock options exercised		8		13		15	2		1
Tax benefits from the vesting of restricted stock awards		10		2		10
Cash proceeds from the exercise of stock options		19		38		63
Unrecognized compensation cost related to nonvested awards													23
Expected weighted-average period recognized for the unrecognized compensation cost													2 years 1 month 6 days
Fair value of restricted stock awards that vested													30	28	26
Number of performance metrics		2																2
Performance metrics period				2 years
Shares issued minimum percentage																	0.00%
Shares issued maximum percentage																	200.00%
Stock awards granted																				132,000	20,000	9,000
Number of shares converted to one class to another														168,000	186,000	168,000	2,000	132,000	147,000			15,000	25,000
ShareBasedCompensationArrangementByShare Based Payment Award Shares Expected To Be Issued In Period																	4,000
Cash-based performance grants minimum																								0.00%
Cash-based performance grants maximum																								200.00%
Cash based performance grant actual payout																									6	14				11	11	6
Cash-based performance grants																											20		14					12
Cash based performance grant liability accrued																												5					2	6
Cash based performance grants, total expected award																																	$ 8

[1] 1 billion shares authorized; 576 million shares and 570 million shares outstanding at December 31, 2012 and 2011, respectively.

[2] 500,000 shares shares authorized at December 31, 2012 and 2011; 274,723 shares outstanding at December 31, 2012 and 2011.

XML

Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Allowance - Customer Receivables	$ 28	$ 29
Allowance - Other	4	8
Common Stock, shares authorized	1,000,000,000
Common stock, shares outstanding	576,000,000	570,000,000
Virginia Electric and Power Company
Allowance - Customer Receivables	10	11
Allowance - Other	$ 3	$ 7
Common Stock, shares authorized	500,000	500,000
Common stock, shares outstanding	274,723	274,723

XML

Consolidated Statements of Income (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Impairment charge	$ 2,100,000,000
Discontinued operation tax expense	$ 27,000,000	$ 9,000,000	$ 34,000,000

XML

Derivatives and Hedge Accounting Activities

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives and Hedge Accounting Activities

DERIVATIVESAND HEDGE ACCOUNTING ACTIVITIES

Dominion and Virginia Power are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as currency exchange and interest rate risks of their business operations. The Companies use derivative instruments to manage exposure to these risks, and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes. As discussed in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivatives are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings. See Note 6 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 December 31, 2012. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)	249		68
Basis(1)	786		534
Electricity (MWh):
Fixed price(1)	20,100,938		12,582,674
FTRs	46,851,683		—
Capacity (MW)	151,025		148,461
Liquids (gallons)(2)	164,682,000		145,698,000
Interest rate	$	1,500,000,000	$	2,250,000,000

(1) Includes options.

(2) Includes NGLs and oil.

For the years ended December 31, 2012, 2011 and 2010, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion's Consolidated Balance Sheet at December 31, 2012:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(28	)	$	(24	)	27 months
Electricity	68			17			36 months
Other	3			2			41 months
Interest rate	(165		)	(21		)	361 months
Total	$	(122	)	$	(26	)

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 resulted in the discontinuance of hedge accounting for certain cash flow hedges in 2010, 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 was determined that the 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) for 2010. The reclassification of gains from AOCI to earnings was partially offset by subsequent changes in fair value for these contracts of $37 million ($23 million after-tax) for 2010.

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Dominion's derivatives and where they are presented in its Consolidated Balance Sheets:

At December 31, 2012	Fair Value  - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
ASSETS
Current Assets
Commodity	$	103	$	379	$	482
Interest rate	36		—		36
Total current derivative assets	139		379		518
Noncurrent Assets
Commodity	130		123		253
Interest rate	57		—		57
Total noncurrent derivative assets(1)	187		123		310
Total derivative assets	$	326	$	502	$	828
LIABILITIES
Current Liabilities
Commodity	$	103	$	341	$	444
Interest rate	66		—		66
Total current derivative liabilities	169		341		510
Noncurrent Liabilities
Commodity	58		93		151
Total noncurrent derivative liabilities(2)	58		93		151
Total derivative liabilities	$	227	$	434	$	661
At December 31, 2011
ASSETS
Current Assets
Commodity	$	176	$	495	$	671
Interest rate	34		—		34
Total current derivative assets	210		495		705
Noncurrent Assets
Commodity	198		96		294
Interest rate	71		—		71
Total noncurrent derivative assets(1)	269		96		365
Total derivative assets	$	479	$	591	$	1,070
LIABILITIES
Current Liabilities
Commodity	$	162	$	530	$	692
Interest rate	222		37		259
Total current derivative liabilities	384		567		951
Noncurrent Liabilities
Commodity	118		78		196
Interest rate	—		10		10
Total noncurrent derivative liabilities(2)	118		88		206
Total derivative liabilities	$	502	$	655	$	1,157

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

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

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 Year Ended December 31, 2012	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)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	188
Purchased gas				(75		)
Electric fuel and other energy-related purchases				(17		)
Total commodity	$	71		$	96		$	10
Interest rate(3)	(84		)	(2		)	(35		)
Total	$	(13	)	$	94		$	(25	)
Year Ended December 31, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	153
Purchased gas				(78		)
Electric fuel and other energy-related purchases				(2		)
Purchased electric capacity				1
Total commodity	$	137		$	74		$	(20	)
Interest rate(3)	(252		)	(8		)	(143		)
Total	$	(115	)	$	66		$	(163	)
Year Ended December 31, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	557
Purchased gas				(155		)
Electric fuel and other energy-related purchases				(8		)
Purchased electric capacity				3
Total commodity	$	139		$	397		$	(17	)
Interest rate(3)	(3		)	109			(27		)
Foreign currency(4)	—			1			(2		)
Total	$	136		$	507		$	(46	)

(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.

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2012			2011			2010
(millions)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue	$	168		$	111		$	67
Purchased gas	(14		)	(35		)	(41		)
Electric fuel and other energy-related purchases	(40		)	(45		)	51
Interest rate(2)	17			(5		)	(37		)
Total	$	131		$	26		$	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 at December 31, 2012. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price	16		—
Basis	8		—
Electricity (MWh):
Fixed price	709,600		—
FTRs	43,570,739		—
Capacity (MW)	107,000		93,800
Interest rate	$	500,000,000	$	250,000,000

For the years ended December 31, 2012, 2011 and 2010, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to the time value of options and changes in the differences between spot prices and forward prices.

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Virginia Power's derivatives and where they are presented in its Consolidated Balance Sheets:

At December 31, 2012	Fair Value  - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
ASSETS
Current Assets
Commodity	$	1	$	5	$	6
Total current derivative assets(1)	1		5		6
Total derivative assets	$	1	$	5	$	6
LIABILITIES
Current Liabilities
Commodity	$	5	$	3	$	8
Interest rate	25		—		25
Total current derivative liabilities	30		3		33
Noncurrent Liabilities
Commodity	1		—		1
Total noncurrent derivative liabilities(2)	1		—		1
Total derivative liabilities	$	31	$	3	$	34
At December 31, 2011
ASSETS
Current Assets
Commodity	$	—	$	2	$	2
Total current derivative assets(1)	—		2		2
Total derivative assets	$	—	$	2	$	2
LIABILITIES
Current Liabilities
Commodity	$	14	$	31	$	45
Interest rate	$	53	$	37	$	90
Total current derivative liabilities	67		68		135
Noncurrent Liabilities
Commodity	2		—		2
Interest rate	—		10		10
Total noncurrent derivative liabilities(2)	2		10		12
Total derivative liabilities	$	69	$	78	$	147

(1) Current derivative assets are presented in other current assets in Virginia Power's Consolidated Balance Sheets.

(2) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power's Consolidated Balance Sheets.

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 Year Ended December 31, 2012	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)
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(4	)
Total commodity	$	(2	)	$	(4	)	$	10
Interest rate(3)	(6		)	—			(35		)
Total	$	(8	)	$	(4	)	$	(25	)
Year Ended December 31, 2011
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Purchased electric capacity				1
Total commodity	$	(3	)	$	—		$	(20	)
Interest rate(3)	(6		)	1			(143		)
Total	$	(9	)	$	1		$	(163	)
Year Ended December 31, 2010
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Purchased electric capacity				4
Total commodity	$	(1	)	$	3		$	(17	)
Interest rate(3)	(1		)	9			(27		)
Foreign currency(4)	—			—			(2		)
Total	$	(2	)	$	12		$	(46	)

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

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

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

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

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2012			2011			2010
(millions)
Derivative Type and Location of Gains (Losses)
Commodity(2)	$	(50	)	$	(45	)	$	51
Interest rate(3)	—			(5		)	(3		)
Total	$	(50	)	$	(50	)	$	48

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

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

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

XML

Long-Term Debt (Total Long Term Debt) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Debt Instrument [Line Items]
Total principal, including VIE	$ 18,988,000,000		$ 18,745,000,000
Securities due within one year, including VIE	(2,223,000,000)	[1]	(1,479,000,000)	[1]
Unamortized discount and premium, net	7,000,000		(23,000,000)
Total long term debt, including VIE	16,851,000,000		17,394,000,000
Fair value hedge valuation	93,000,000	[2]	105,000,000	[2]
Debt, Weighted Average Interest Rate	4.53%	[1],[3]
Precentage of the applicable conversion price	120.00%
Redemption percentage of principal amount	100.00%
Basis spread (percentage)	2.30%
Unamortized premium	18,000,000		48,000,000
Assets pledged as collateral			552,000,000
Unamortized premium and discount	23,000,000		4,000,000
Minimum consecutive trading days	20 days
Maximum consecutive trading days	30 days
1.4% to 7.195%, due 2012 to 2017
Debt Instrument [Line Items]
Debt instrument interest rate minimum	1.40%
Debt instrument interest rate maximum	7.195%
2.75% to 8.875% due 2018 to 2042
Debt Instrument [Line Items]
Debt instrument interest rate minimum	2.75%
Debt instrument interest rate maximum	8.875%
Unsecured Convertible Senior Notes, 2.125%, due 2023
Debt Instrument [Line Items]
Debt instrument, interest rate	2.125%
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031
Debt Instrument [Line Items]
Debt instrument interest rate minimum	7.83%
Debt instrument interest rate maximum	8.40%
7.5% and 8.375%, due 2064 and 2066
Debt Instrument [Line Items]
Debt instrument interest rate minimum	7.50%
Debt instrument interest rate maximum	8.375%
5.0% and 6.625%, due 2013 and 2014
Debt Instrument [Line Items]
Debt instrument interest rate minimum	5.00%
Debt instrument interest rate maximum	6.625%
6.8% and 6.875%, due 2026 and 2027
Debt Instrument [Line Items]
Debt instrument interest rate minimum	6.80%
Debt instrument interest rate maximum	6.875%
Secured Senior Notes, 5.13% to 5.78%, due 2013
Debt Instrument [Line Items]
Debt instrument interest rate minimum	5.03%
Debt instrument interest rate maximum	5.78%
Secured Senior Note, 7.33%, due 2020
Debt Instrument [Line Items]
Debt instrument, interest rate	7.33%
2.25% to 5.75%, due 2033 to 2042
Debt Instrument [Line Items]
Debt instrument interest rate minimum	2.25%
Debt instrument interest rate maximum	5.75%
8.875% Senior Notes Due 2019
Debt Instrument [Line Items]
Senior Notes	600,000,000
Debt instrument, interest rate	8.875%
Long term debt maturity date	2019
5.25% Senior Notes Due 2033
Debt Instrument [Line Items]
Senior Notes	510,000,000
Debt instrument, interest rate	5.25%
Long term debt maturity date	2033
6.3% 2006 Series B Enhanced Junior Subordinated Notes
Debt Instrument [Line Items]
Debt instrument, interest rate	6.30%
Enhanced junior subordinated notes	500,000,000
Senior Notes | Variable rate, due 2013
Debt Instrument [Line Items]
Total principal, including VIE	400,000,000		0
Debt, Weighted Average Interest Rate	0.41%	[3]
Senior Notes | 1.4% to 7.195%, due 2012 to 2017
Debt Instrument [Line Items]
Total principal, including VIE	3,041,000,000		3,545,000,000
Debt, Weighted Average Interest Rate	3.72%	[3]
Senior Notes | 2.75% to 8.875% due 2018 to 2042
Debt Instrument [Line Items]
Total principal, including VIE	5,099,000,000	[4]	4,399,000,000	[4]
Debt, Weighted Average Interest Rate	5.71%	[3],[4]
Senior Notes | Unsecured Convertible Senior Notes, 2.125%, due 2023
Debt Instrument [Line Items]
Total principal, including VIE	82,000,000	[5]	143,000,000	[5]
Senior Notes | 5.0% and 6.625%, due 2013 and 2014
Debt Instrument [Line Items]
Total principal, including VIE	622,000,000	[6]	622,000,000	[6]
Debt, Weighted Average Interest Rate	5.06%	[3],[6]
Senior Notes | 6.8% and 6.875%, due 2026 and 2027
Debt Instrument [Line Items]
Total principal, including VIE	89,000,000	[6]	89,000,000	[6]
Debt, Weighted Average Interest Rate	6.81%	[3],[6]
Senior Notes | Secured Senior Notes, 5.13% to 5.78%, due 2013
Debt Instrument [Line Items]
Total principal, including VIE	842,000,000	[7]	842,000,000	[7]
Debt, Weighted Average Interest Rate	5.07%	[3],[7]
Senior Notes | Secured Senior Note, 7.33%, due 2020
Debt Instrument [Line Items]
Total principal, including VIE	145,000,000	[8]	159,000,000	[8]
Junior Subordinated Notes | Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031
Debt Instrument [Line Items]
Total principal, including VIE	268,000,000		268,000,000
Debt, Weighted Average Interest Rate	7.85%	[3]
Junior Subordinated Notes | 7.5% and 8.375%, due 2064 and 2066
Debt Instrument [Line Items]
Total principal, including VIE	985,000,000		985,000,000
Debt, Weighted Average Interest Rate	8.11%	[3]
Junior Subordinated Notes | Enhanced Junior Subordinated Notes, variable rate, due 2066
Debt Instrument [Line Items]
Total principal, including VIE	380,000,000	[9]	468,000,000	[9]
Debt, Weighted Average Interest Rate	2.77%	[3],[9]
Tax-Exempt Financings | 2.25% to 5.75%, due 2033 to 2042
Debt Instrument [Line Items]
Total principal, including VIE	284,000,000	[10]	284,000,000	[10]
Debt, Weighted Average Interest Rate	3.34%	[10],[3]
Tax-Exempt Financings | Variable rate, due 2041
Debt Instrument [Line Items]
Total principal, including VIE	75,000,000	[10]	75,000,000	[10]
Debt, Weighted Average Interest Rate	1.16%	[10],[3]
Virginia Electric and Power Company
Debt Instrument [Line Items]
Total principal, including VIE	6,676,000,000	[10]	6,866,000,000	[10]
Securities due within one year, including VIE	(418,000,000)		(616,000,000)
Unamortized discount and premium, net	7,000,000		4,000,000
Total long term debt, including VIE	6,251,000,000		6,246,000,000
Debt, Weighted Average Interest Rate	4.88%	[3]
Virginia Electric and Power Company | Line of Credit
Debt Instrument [Line Items]
Credit facility, to support letters of credit	120,000,000
Virginia Electric and Power Company | 4.75% to 8.625%, due 2012 to 2017
Debt Instrument [Line Items]
Debt instrument interest rate minimum	4.75%
Debt instrument interest rate maximum	8.625%
Virginia Electric and Power Company | 2.95% to 8.875%, due 2018 to 2038
Debt Instrument [Line Items]
Debt instrument interest rate minimum	2.95%
Debt instrument interest rate maximum	8.75%
Virginia Electric and Power Company | 1.5% to 6.5%, due 2017 to 2040
Debt Instrument [Line Items]
Debt instrument interest rate minimum	1.50%
Debt instrument interest rate maximum	6.50%
Virginia Electric and Power Company | Senior Notes | 4.75% to 8.625%, due 2012 to 2017
Debt Instrument [Line Items]
Total principal, including VIE	1,706,000,000		2,321,000,000
Debt, Weighted Average Interest Rate	5.50%	[3]
Virginia Electric and Power Company | Senior Notes | 2.95% to 8.875%, due 2018 to 2038
Debt Instrument [Line Items]
Total principal, including VIE	4,008,000,000		3,558,000,000
Debt, Weighted Average Interest Rate	5.83%	[3]
Virginia Electric and Power Company | Tax-Exempt Financings | Variable rates, due 2016 to 2041
Debt Instrument [Line Items]
Total principal, including VIE	454,000,000	[11]	454,000,000	[11]
Debt, Weighted Average Interest Rate	1.14%	[11],[3]
Virginia Electric and Power Company | Tax-Exempt Financings | 1.5% to 6.5%, due 2017 to 2040
Debt Instrument [Line Items]
Total principal, including VIE	$ 508,000,000	[11]	$ 533,000,000	[11]
Debt, Weighted Average Interest Rate	3.65%	[11],[3]

[1] Includes $23 million of net unamortized premium and fair value hedge valuation in 2012 and $4 million of net unamortized discount in 2011.

[2] Represents the valuation of certain fair value hedges associated with Dominion's fixed rate debt.

[3] Represents weighted-average coupon rates for debt outstanding as of December 31, 2012.

[4] At the option of holders, $510 million of Dominion's 5.25% senior notes due 2033 and $600 million of Dominion's 8.875% senior notes due 2019 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015 and January 2014, respectively.

[5] Convertible into a combination of cash and shares of Dominion's common stock at any time when the closing price of common stock equals 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter. At the option of holders on December 15, 2013 or 2018, these securities are subject to redemption at 100% of the principal amount plus accrued interest. These senior notes have been callable by Dominion since December 15, 2011.

[6] Represents debt assumed by Dominion from the merger of its former CNG subsidiary.

[7] Juniper notes issued in 2004 and consolidated in October 2011 due to Dominion becoming the primary beneficiary of this VIE. This amount excludes $18 million and $48 million of unamortized premium in 2012 and 2011, respectively. The debt is non-recourse to Dominion and is secured by Juniper's assets.

[8] Represents debt associated with Kincaid. The debt is non-recourse to Dominion and is secured by the facility's assets ($552 million at December 31, 2012) and revenue. Dominion announced in the third quarter of 2012 that it was pursuing the sale of Kincaid. Dominion anticipates redeeming the notes as a condition to a sale of Kincaid.

[9] In September 2011, the $500 million 6.3% September 2006 hybrids began bearing interest at the three-month LIBOR plus 2.3%, reset quarterly.

[10] Includes debt issued by the Massachusetts Development Finance Agency on behalf of Brayton Point. Dominion announced in the third quarter of 2012 that it was pursuing the sale of Brayton Point.

[11] These financings relate to certain pollution control equipment at Virginia Power's generating facilities. Certain variable rate tax-exempt financings are supported by a $120 million credit facility that terminates in September 2017.

XML

Goodwill and Intangible Assets (Components of Intangible Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 864	$ 968
Accumulated Amortization	328	(331)
Virginia Electric and Power Company
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	303	285
Accumulated Amortization	122	(102)
Software, licenses and other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	859	888
Accumulated Amortization	327	(278)
Software, licenses and other | Virginia Electric and Power Company
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	303	285
Accumulated Amortization	122	(102)
Emissions allowances
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	5	80
Accumulated Amortization	$ 1	$ (53)

XML

Goodwill and Intangible Assets (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Goodwill [Line Items]
Amortization expense for intangible assets	$ 82	$ 78	$ 107
Acquisition of intangible assets	102
Weighted-average amortization period (years)	19 years
Virginia Electric and Power Company
Goodwill [Line Items]
Amortization expense for intangible assets	22	22	26
Acquisition of intangible assets	$ 53
Weighted-average amortization period (years)	31 years

XML

Employee Benefit Plans (Effect of One Percentage Point Change on Benefit Plans) (Details) (Other Postretirement Plans, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Effect of one percentage point increase on total of service and interest cost components	$ 17
Effect of one percentage point increase on other postretirement benefit obligation	218
Effect of one percentage point decrease on total of service and interest cost components	(16)
Effect of one percentage point decrease on other postretirement benefit obligation	$ (172)

XML

Commitments and Contingencies (Workforce Reduction Program) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2010	Dec. 31, 2010
Loss Contingencies [Line Items]
Percent of workforce reduction	9.00%
Before tax severance costs	$ 338
After-tax severance costs	206
Workforce reduction expenditure		109
Virginia Electric and Power Company
Loss Contingencies [Line Items]
Percent of workforce reduction	11.00%
Before tax severance costs	202
After-tax severance costs	123
Workforce reduction expenditure		$ 104

XML

Employee Benefit Plans (Net Periodic Benefit (Credit) Cost and Amounts Recognized in Other Comprehensive Income and Regulatory Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	$ (509)		$ (519)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	116		108		102
Interest cost	268		258		266
Expected return on plan assets	(430)		(440)		(410)
Amortization of prior service (credit) cost	3		3		3
Amortization of net actuarial loss	132		96		59
Settlements and curtailments	0	[1]	0	[1]	136	[1]
Special termination benefits	0	[2]	0	[2]	(10)	[2]
Net periodic benefit (credit) cost	89		25		166
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	786		534		95
Prior service (credit) cost	0		0		1
Settlements and curtailments	0	[1]	0	[1]	(50)	[1]
Amortization of net actuarial loss	(132)		(96)		(59)
Amortization of prior service credit (cost)	3		3		3
Total recognized in other comprehensive income and regulatory assets and liabilities	651		435		(16)
Significant assumptions used to determine periodic cost:
Discount rate	5.50%		5.90%		6.60%
Expected long-term rate of return on plan assets	8.50%		8.50%		8.50%
Weighted average rate of increase for compensation	4.21%		4.61%		4.76%
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	44		48		56
Interest cost	79		94		101
Expected return on plan assets	(79)		(79)		(69)
Amortization of prior service (credit) cost	(13)		(13)		(7)
Amortization of net actuarial loss	6		12		12
Settlements and curtailments	(4)	[1]	1	[1]	37	[1]
Special termination benefits	0	[2]	0	[2]	(1)	[2]
Net periodic benefit (credit) cost	33		63		131
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	139		(157)		13
Prior service (credit) cost	1		(70)		0
Settlements and curtailments	(2)	[1]	(1)	[1]	(1)	[1]
Amortization of net actuarial loss	(6)		(12)		(12)
Amortization of prior service credit (cost)	(13)		(13)		(7)
Total recognized in other comprehensive income and regulatory assets and liabilities	$ 145		$ (227)		$ 7
Significant assumptions used to determine periodic cost:
Discount rate	5.50%		5.90%		6.60%
Expected long-term rate of return on plan assets	7.75%		7.75%		7.75%
Weighted average rate of increase for compensation	4.22%		4.62%		4.79%
Healthcare cost trend rate	7.00%	[3]	7.00%	[3]	7.00%	[3]
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	4.60%	[3]	4.60%	[3]	4.60%	[3]
Year that the rate reaches the ultimate trend rate	2061	[3]	2060	[3]	2060	[3]

[1] 2012 amounts relate to the sale of Salem Harbor. 2010 amounts relate to the sales of Peoples and Dominion's Appalachian E&P operations and a workforce reduction program.

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

[3] Assumptions used to determine periodic cost for the following year.

XML

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012	Jan. 31, 2013	Jun. 30, 2012
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
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		576,309,631
Entity Well Known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 22,300,000,000
Virginia Electric and Power Company
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
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
Entity Well Known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 0

XML

Commitments and Contingencies Commitment and Contingencies (Schedule of Long Term Purchase Commitments) (Details) (Virginia Electric and Power Company, USD $)	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010
Long-term Purchase Commitment [Line Items]
Present value of total commitment for capacity payments	$ 1,400,000,000
Purchased electric capacity
Long-term Purchase Commitment [Line Items]
2013	350,000,000	[1]
2014	358,000,000	[1]
2015	337,000,000	[1]
2016	275,000,000	[1]
2017	181,000,000	[1]
Thereafter	327,000,000	[1]
Total	1,828,000,000	[1]
Payments	337,000,000		338,000,000	344,000,000
Energy payments
Long-term Purchase Commitment [Line Items]
Payments	$ 214,000,000		$ 275,000,000	$ 303,000,000

[1] Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2012, the present value of Virginia Power's total commitment for capacity payments is $1.4 billion. Capacity payments totaled $337 million, $338 million, and $344 million, and energy payments totaled $214 million, $275 million, and $303 million for 2012, 2011 and 2010, respectively.

XML

Earnings Per Share

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

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

	2012		2011		2010
(millions, except EPS)
Net income attributable to Dominion	$	302	$	1,408	$	2,808
Average shares of common stock outstanding-Basic	572.9		573.1		588.9
Net effect of potentially dilutive securities(1)	1.0		1.5		1.2
Average shares of common stock outstanding-Diluted	573.9		574.6		590.1
Earnings Per Common Share-Basic	$	0.53	$	2.46	$	4.77
Earnings Per Common Share-Diluted	$	0.53	$	2.45	$	4.76

(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 years ended December 31, 2012, 2011 and 2010.

XML

Derivatives and Hedge Accounting Activities (Gains and Losses on our Derivatives in Cash Flow Hedging Relationships) (Details) (Cash Flow Hedges, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	$ (13)	[1]	$ (115)	[1]	$ 136	[1]
Amount of Gain (Loss) Reclassified from AOCI to Income	94		66		507
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	(25)	[2]	(163)	[2]	(46)	[2]
Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	71	[1]	137	[1]	139	[1]
Amount of Gain (Loss) Reclassified from AOCI to Income	96		74		397
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	10	[2]	(20)	[2]	(17)	[2]
Commodity | Operating Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Income	188		153		557
Commodity | Purchased gas
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Income	(75)		(78)		(155)
Commodity | Electric fuel and other energy-related purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Income	(17)		(2)		(8)
Commodity | Purchased electric capacity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Income			1		3
Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	(84)	[1],[3]	(252)	[1],[3]	(3)	[1],[3]
Amount of Gain (Loss) Reclassified from AOCI to Income	(2)	[3]	(8)	[3]	109	[3]
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	(35)	[2],[3]	(143)	[2],[3]	(27)	[2],[3]
Foreign currency
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)					0	[1],[4]
Amount of Gain (Loss) Reclassified from AOCI to Income					1	[4]
Increase (Decrease) in Derivatives Subject to Regulatory Treatment					(2)	[2],[4]
Virginia Electric and Power Company
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	(8)	[5]	(9)	[5]	(2)	[5]
Amount of Gain (Loss) Reclassified from AOCI to Income	(4)		1		12
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	(25)	[6]	(163)	[6]	(46)	[6]
Virginia Electric and Power Company | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	(2)	[5]	(3)	[5]	(1)	[5]
Amount of Gain (Loss) Reclassified from AOCI to Income	(4)		0		3
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	10	[6]	(20)	[6]	(17)	[6]
Virginia Electric and Power Company | Commodity | Electric Fuel and Energy Purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Income	(4)		(1)		(1)
Virginia Electric and Power Company | Commodity | Purchased electric capacity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Income			1		4
Virginia Electric and Power Company | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	(6)	[5],[7]	(6)	[5],[7]	(1)	[5],[7]
Amount of Gain (Loss) Reclassified from AOCI to Income	0	[7]	1	[7]	9	[7]
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	(35)	[6],[7]	(143)	[6],[7]	(27)	[6],[7]
Virginia Electric and Power Company | Foreign currency
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)					0	[5],[8]
Amount of Gain (Loss) Reclassified from AOCI to Income					0	[8]
Increase (Decrease) in Derivatives Subject to Regulatory Treatment					$ (2)	[6],[8]

[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.

[5] Amounts deferred into AOCI have no associated effect in Virginia Power's Consolidated Statements of Income.

[6] 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.

[7] Amounts recorded in Virginia Power's Consolidated Statements of Income are classified in interest and related charges.

[8] Amounts recorded in Virginia Power's Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.

XML

Property, Plant and Equipment (Share of Jointly-Owned Power Stations) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Millstone Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	93.50%	[1]
Plant in service	$ 993	[1]
Accumulated depreciation	(236)	[1]
Nuclear fuel	456	[1]
Accumulated amortization of nuclear fuel	(272)	[1]
Plant under construction	36	[1]
Virginia Electric and Power Company | Bath County Pumped Storage Station
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	60.00%	[2]
Plant in service	1,024	[2]
Accumulated depreciation	(521)	[2]
Nuclear fuel	0	[2]
Accumulated amortization of nuclear fuel	0	[2]
Plant under construction	27	[2]
Virginia Electric and Power Company | North Anna
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	88.40%	[2]
Plant in service	2,392	[2]
Accumulated depreciation	(1,072)	[2]
Nuclear fuel	502	[2]
Accumulated amortization of nuclear fuel	(390)	[2]
Plant under construction	77	[2]
Virginia Electric and Power Company | Clover Power Station
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	50.00%	[2]
Plant in service	568	[2]
Accumulated depreciation	(192)	[2]
Nuclear fuel	0	[2]
Accumulated amortization of nuclear fuel	0	[2]
Plant under construction	$ 6	[2]

[1] Unit jointly owned by Dominion.

[2] Units jointly owned by Virginia Power.

XML

Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011		Dec. 31, 2010
Net income including noncontrolling interests	$ 329	$ 1,426	[1]	$ 2,825	[1]
Net income attributable to Dominion	302	1,408	[1]	2,808	[1]
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of tax	(8)	(67)		84
Changes in unrealized net gains (losses) on investment securities, net of tax	108	11		89
Changes in net unrecognized pension and other postretirement benefit costs, net of tax	(330)	(231)		(18)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of tax	(60)	(38)		(314)
Net realized gains on investment securities, net of tax	(25)	6		(14)
Net pension and other postretirement benefit costs, net of tax	48	39		54
Total other comprehensive loss	(267)	(280)		(119)
Comprehensive income including noncontrolling interests	62	1,146		2,706
Comprehensive income attributable to noncontrolling interests	(27)	(18)		(17)
Comprehensive income	35	1,128		2,689
Virginia Electric and Power Company
Net income attributable to Dominion	1,050	822		852
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of tax	(5)	(6)		(1)
Changes in unrealized net gains (losses) on investment securities, net of tax	13	2		9
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of tax	2	(1)		(8)
Net realized gains on investment securities, net of tax	(4)	0		(2)
Total other comprehensive loss	6	(5)		(2)
Comprehensive income	$ 1,056	$ 817		$ 850

[1] Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

XML

Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Significant Accounting Policies

SIGNIFICANT ACCOUNTING POLICIES

General

Dominion and Virginia Power 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, expenses and cash flows for the periods presented. Actual results may differ from those estimates.

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

Dominion and Virginia Power report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.

Dominion maintains pension and other postretirement benefit plans. Virginia Power participates in certain of these plans. See Note 21 for further information on these plans.

Certain amounts in the 2011 and 2010 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2012 presentation for comparative purposes. The reclassifications did not affect the Companies' net income, total assets, liabilities, equity or cash flows.

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

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. The Companies collect sales, consumption and consumer utility taxes; however, these amounts are excluded from revenue. Dominion's customer receivables at December 31, 2012 and 2011 included $411 million and $423 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power's customer receivables at December 31, 2012 and 2011 included $348 million and $360 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers.

The primary types of sales and service activities reported as operating revenue for Dominion are as follows:

• Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

• Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;

• Regulated gas sales consist primarily of state-regulated retail natural gas sales and related distribution services;

• Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties;

• Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services and associated derivative activity. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; and

• Other revenue consists primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes miscellaneous service revenue from electric and gas distribution operations, and gas processing and handling revenue.

The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:

• Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and

• Other revenue consists primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Where permitted by regulatory authorities, the differences between Virginia Power's actual electric fuel and purchased energy expenses and Dominion's purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.

Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 83% is currently subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.

Income Taxes

A consolidated federal income tax return is filed for Dominion and its subsidiaries, including Virginia Power. In addition, where applicable, combined income tax returns for Dominion and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed. Virginia Power participates in an intercompany tax sharing agreement with Dominion and its subsidiaries, and its current income taxes are based on its taxable income or loss, determined on a separate company basis.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

Dominion and Virginia Power recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the consolidated balance sheets and current payables are included in accrued interest, payroll and taxes on the consolidated balance sheets, except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities.

Dominion and Virginia Power recognize changes in estimated interest payable on net underpayments of income taxes in interest expense. Changes in interest receivable related to net overpayments of income taxes and estimated penalties that may result from the settlement of some uncertain tax positions are recognized in other income. In its Consolidated Statements of Income for 2012, Dominion recognized interest income of $8 million and interest expense of $3 million and a reduction in penalties of less than $1 million. In 2011, Dominion recognized interest income of $12 million and interest expense of $7 million and a reduction in penalties of less than $1 million. In 2010, Dominion recognized a reduction in interest expense of $18 million and a reduction in penalties of less than $1 million. Dominion had accrued interest receivable of $5 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2012 and interest receivable of $48 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2011.

Virginia Power's interest and penalties were immaterial in 2012 and 2010. In 2011, Virginia Power recognized interest income of $12 million, and penalties were immaterial. Virginia Power had accrued interest receivable of $17 million at December 31, 2011.

At December 31, 2012, Virginia Power's Consolidated Balance Sheet included $10 million of federal income taxes payable and $36 million of noncurrent federal and state income taxes payable.

At December 31, 2011, Virginia Power's Consolidated Balance Sheet included $18 million of current federal income taxes receivable, $34 million of current state income taxes payable and $110 million of noncurrent federal and state income taxes payable.

Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 2012 and 2011, Dominion's accounts payable included $53 million and $75 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 2012 and 2011, Virginia Power's accounts payable included $30 million and $40 million, respectively, of checks outstanding but not yet presented for payment. For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Derivative Instruments

Dominion and Virginia Power use derivative instruments such as futures, swaps, forwards, options and FTRs to manage the commodity, currency exchange and financial market risks of their business operations.

All derivatives, other than those for which an exception applies, are reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.

Dominion and Virginia Power do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion had margin assets of $212 million and $319 million associated with cash collateral at December 31, 2012 and 2011, respectively. Dominion had margin liabilities of $4 million and $66 million associated with cash collateral at December 31, 2012 and 2011, respectively. Virginia Power had margin assets of $18 million and $41 million associated with cash collateral at December 31, 2012 and 2011, respectively. Virginia Power's margin liabilities associated with cash collateral were not material at December 31, 2012 and 2011.

To manage price risk, Dominion and Virginia Power hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. As part of Dominion's strategy to market energy and manage related risks, it also manages a portfolio of commodity-based financial derivative instruments held for trading purposes. Dominion uses established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and uses various derivative instruments to reduce risk by creating offsetting market positions.

Statement of Income Presentation:

• Derivatives Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis.

• Derivatives Not Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses or interest and related charges based on the nature of the underlying risk.

In Virginia Power's generation operations, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.

DERIVATIVE INSTRUMENTS DESIGNATEDAS HEDGING INSTRUMENTS

Dominion and Virginia Power designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, Dominion and Virginia Power formally document the relationship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using the hedging instrument. The Companies assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges-A majority of Dominion's and Virginia Power's hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and other energy-related products. The Companies also use foreign currency contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which Dominion and Virginia Power are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Fair Value Hedges-Dominion also uses fair value hedges to mitigate the fixed price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, Dominion and Virginia Power have designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item's fair value. Derivative gains and losses from the hedged item are reclassified to earnings when the hedged item is included in earnings, or earlier, if the hedged item no longer qualifies for hedge accounting. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting.

See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.

Property, Plant and Equipment

Property, plant and equipment, including additions and replacements is recorded at original cost, consisting of labor and materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as it is incurred.

In 2012, 2011 and 2010, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $91 million, $85 million and $102 million, respectively. In 2012, 2011 and 2010, Virginia Power capitalized AFUDC to property, plant and equipment of $31 million, $31 million and $61 million, respectively. Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2012, 2011 and 2010, Virginia Power recorded $37 million, $20 million and $13 million of AFUDC related to these projects, respectively.

For Virginia Power property subject to cost-of-service rate regulation, including electric distribution, electric transmission, and generation property and for certain Dominion natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be retired or abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be retired or abandoned.

For Dominion and Virginia Power property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property's net book value at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. Dominion's and Virginia Power's depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2012	2011	2010
(percent)
Dominion
Generation	2.62	2.68	2.59
Transmission	2.17	2.26	2.24
Distribution	3.17	3.19	3.20
Storage	2.59	2.64	2.75
Gas gathering and processing	2.49	2.52	2.39
General and other	4.55	4.66	4.60
Virginia Power
Generation	2.62	2.68	2.59
Transmission	1.98	2.03	1.94
Distribution	3.32	3.33	3.33
General and other	4.32	4.38	4.28

Dominion's nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

Asset	Estimated Useful Lives
Merchant generation-nuclear	34-44 years
Merchant generation-other	27-40 years
General and other	5-59 years

Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.

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, Dominion no longer has any significant gas and oil properties subject to the ceiling test calculation.

In 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 and recognized a gain from the sale of substantially all of its Appalachian E&P operations, as discussed in Note 3.

Emissions Allowances

Emissions allowances permit the holder of the allowance to emit certain gaseous by-products of fossil fuel combustion, including SO₂, NO_X and CO₂. SO₂ and NO_X emissions allowances are issued to Dominion and Virginia Power by the EPA and may also be purchased and sold via third party contracts. CO₂ emissions allowances are available for purchase by Dominion through quarterly auctions held by participating RGGI states. Compliance with the RGGI requirements only applies to certain of Dominion's merchant power stations located in the Northeast.

Allowances held may be transacted with third parties or consumed as these emissions are generated. Allowances allocated to or acquired by the Companies' generation operations are held primarily for consumption.

Allowances held for consumption are classified as intangible assets in the Consolidated Balance Sheets. Carrying amounts are based on the cost to acquire the allowances or, in the case of a business combination, on the fair values assigned to them in the allocation of the purchase price of the acquired business. A portion of Dominion's and Virginia Power's SO₂ and NO_X allowances are issued by the EPA at zero cost.

These allowances are amortized in the periods the emissions are generated, with the amortization reflected in depreciation, depletion and amortization in the Consolidated Statements of Income. Purchases and sales of these allowances are reported as investing activities in the Consolidated Statements of Cash Flows and gains or losses resulting from sales are reported in other operations and maintenance expense in the Consolidated Statements of Income. See Note 6 for discussion of impairments related to emissions allowances.

Long-Lived and Intangible Assets

Dominion and Virginia Power perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for a discussion of impairments related to certain long-lived assets and intangible assets with finite lives.

Regulatory Assets and Liabilities

The accounting for Dominion's regulated gas and Virginia Power's regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made.

Asset Retirement Obligations

Dominion and Virginia Power recognize AROs at fair value as incurred or when sufficient information becomes available to

determine a reasonable estimate of the fair value of future retirement activities to be performed. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Dominion reports accretion of AROs associated with its natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Virginia Power reports accretion of AROs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Accretion of all other AROs is reported in other operations and maintenance expense in the Consolidated Statements of Income.

Amortization of Debt Issuance Costs

Dominion and Virginia Power defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized over the lives of the new issuances.

Investments

MARKETABLE EQUITYAND DEBT SECURITIES

Dominion accounts for and classifies investments in marketable equity and debt securities as trading or available-for-sale securities. Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities.

• Trading securities include marketable equity and debt securities held by Dominion in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

• Available-for-sale securities include all other marketable equity and debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power's nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other available-for-sale securities, including those held in Dominion's merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

In determining realized gains and losses for marketable equity and debt securities, the cost basis of the security is based on the specific identification method.

NON-MARKETABLE INVESTMENTS

Dominion and Virginia Power account for illiquid and privately held securities for which market prices or quotations are not readily available under either the equity or cost method. Non-marketable investments include:

• Equity method investments when Dominion and Virginia Power have the ability to exercise significant influence, but not control, over the investee. Dominion's investments are included in investments in equity method affiliates and Virginia Power's investments are included in other investments in their Consolidated Balance Sheets. Dominion and Virginia Power record equity method adjustments in other income in the Consolidated Statements of Income including: their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

• Cost method investments when Dominion and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion's and Virginia Power's investments are included in other investments and nuclear decommissioning trust funds.

OTHER-THAN-TEMPORARY IMPAIRMENT

Dominion and Virginia Power periodically review their investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in fair value of any security is determined to be other-than-temporary, the security is written down to its fair value at the end of the reporting period.

Decommissioning Trust Investments-Special Considerations

• The recognition provisions of the FASB's other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities.

• Debt Securities- Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, the Companies record the credit loss in earnings and any remaining portion of the unrealized loss in other comprehensive income. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

• Equity securities and other investments- Dominion's and Virginia Power's method of assessing other-than-temporary declines requires demonstrating the ability to hold individual securities for a period of time sufficient to allow for the anticipated recovery in their market value prior to the consideration of the other criteria mentioned above. Since the Companies have limited ability to oversee the day-to-day management of nuclear decommissioning trust fund investments, they do not have the ability to ensure investments are held through an anticipated recovery period. Accordingly, they consider all equity and other securities as well as non-marketable investments held in nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired.

Inventories

Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory used in East Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at $24 million and $48 million at December 31, 2012 and December 31, 2011, respectively. Based on the average price of gas purchased during 2012 and 2011, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $69 million and $86 million, respectively. Stored gas inventory held by Hope and certain nonregulated gas operations is valued using the weighted-average cost method.

Gas Imbalances

Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion values these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion from other parties are reported in other current assets and imbalances that Dominion owes to other parties are reported in other current liabilities in the Consolidated Balance Sheets.

Goodwill

Dominion evaluates goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.

XML

Nature of Operations

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

NATUREOF 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 North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power's common stock is owned by Dominion. Dominion's operations also include a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, an LNG import and storage facility in Maryland and regulated gas transportation and distribution operations in Ohio and West Virginia. Dominion's nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations.

Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are expected to be and are currently discontinued, which is discussed in Note 3. In addition, Corporate and Other includes specific items attributable to Dominion's operating segments that are not included in profit measures evaluated by executive management in assessing the segments' performance or allocating resources among the segments.

Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments' performance or allocating resources among the segments. See Note 25 for further discussion of Dominion's and Virginia Power's operating segments.

XML

Regulatory Matters

12 Months Ended

Dec. 31, 2012

Regulatory Matters [Abstract]

Regulatory Matters

REGULATORY MATTERS

Regulatory Matters Involving Potential Loss Contingencies

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

FERC - Electric

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

Rates

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

In July 2008, Virginia Power filed an application with FERC requesting a revision to its revenue requirement to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 1.5% for four of the projects (including the Meadow Brook-to-Loudoun and Carson-to-Suffolk lines, which were completed in 2011) and an incentive of 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008, the incentives were included in the PJM Tariff, and billing for the incentives was made accordingly. In 2012, PJM canceled one of the eleven projects with an estimated cost of $7 million. The total cost for the other ten projects included in Virginia Power's formula rate for 2013 is $852 million and the remaining projects were completed in 2012.  Numerous parties sought rehearing of the FERC order in August 2008, and in May 2012 FERC denied rehearing.  In July 2012, the North Carolina Commission filed an appeal of the FERC orders granting the incentives with the Fourth Circuit Court of Appeals.  Although Virginia Power cannot predict the outcome of the appeal, it is not expected to have a material effect on results of operations.

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

PJM

In November 2011, PJM issued a formal notification that it would recalculate certain ancillary service revenues that had previously been paid during 2009, 2010 and 2011. Also in November 2011, PJM requested FERC permission to suspend its rebilling and repayment obligations associated with the recalculation of such revenues and petitioned FERC to establish a proceeding to determine the appropriate recalculations for the revenues during this period.  In December 2011, FERC permitted the suspension of rebilling and repayment by PJM, subject to the outcome of FERC's proceedings to determine the appropriate revenue recalculation.  In April 2012, FERC issued an Order Establishing Hearing and Settlement Judge Procedures to address the appropriate recalculation of the ancillary service credits PJM will be required to collect from Virginia Power. In August 2012, PJM filed a settlement on behalf of itself, Virginia Power and the PJM Market Monitor. In November 2012, FERC approved the settlement resolving all issues in the proceeding. As of September 30, 2012, Virginia Power had accrued a liability of $33 million, and in January 2013, Virginia Power paid PJM approximately $33 million, resolving the matter.

Other Regulatory Matters

Electric Regulation in Virginia

The enactment of the Regulation Act in 2007 significantly changed electric service regulation in Virginia by instituting a modified cost-of-service rate model. With respect to most classes of customers, the Regulation Act ended Virginia's planned transition to retail competition for its electric supply service.

The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. It provides for enhanced returns on capital expenditures on specific new generation projects, including but not limited to combined cycle gas generation, nuclear generation, clean coal/carbon capture compatible generation, and renewable generation projects. The Regulation Act also continues statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. Legislation was enacted in February 2013 that amends the Regulation Act prospectively. See Future Issues and Other Matters in Item 7. MD&A for a discussion of this legislation.

If the Virginia Commission's future rate decisions, including actions relating to Virginia Power's rate adjustment clause filings, differ materially from Virginia Power's expectations, it may adversely affect its results of operations, financial condition and cash flows.

2011 Biennial Review

Pursuant to the Regulation Act and the Virginia Settlement Approval Order, in March 2011, Virginia Power submitted its base rate filing and accompanying schedules in support of the first biennial review of its base rates, terms and conditions, as well as of its earnings for the 2009 and 2010 test period. The biennial review included a determination of whether Virginia Power's

earnings for the 2009 and 2010 combined test years were within 50 basis points of the authorized ROE of 11.9% established in the Virginia Settlement Approval Order, as well as authorization of an ROE which will be applicable to base rates and rate adjustment clauses and which will be used to measure base rate earnings during the 2013 biennial review proceeding. As a result of the Virginia Settlement Approval Order and the Regulation Act, Virginia Power's base rates are not subject to change based on the 2011 biennial review. In November 2011, the Virginia Commission issued the Biennial Review Order.

In the Biennial Review Order, the Virginia Commission declined to award a performance incentive for generating plant performance, customer service or operating efficiency in connection with the 2009-2010 biennial review. Instead, in March 2012, the Virginia Commission issued an order initiating a rulemaking proceeding to develop specific performance metrics and nationally recognized standards for determining positive or negative performance incentives for electric utilities. Such incentive criteria would be applied in future biennial review proceedings.

In September 2012, the Virginia Commission issued an Order for Notice and Hearing in the separate rulemaking proceeding to develop specific performance standards based on nationally recognized standards for the Virginia Commission's consideration in determining positive or negative performance incentives for electric utilities. The Virginia Commission modified the proposed rules and regulations for performance incentives filed by the Staff of the Virginia Commission, allowed for further comments by November 2012 on the proposed rules and regulations as modified, and held a public hearing in November 2012. In January 2013, the Virginia Commission issued its order adopting revised Performance Incentive rules and regulations effective February 1, 2013.

Base ROE

The Virginia Commission determined that Virginia Power's new authorized ROE is 10.9%, inclusive of a performance incentive of 50 basis points for meeting certain RPS targets. As discussed below, this ROE will serve as the ROE against which Virginia Power's earned return will be compared for the test periods in the 2013 biennial review proceeding. The Virginia Commission ordered that the 50 basis point RPS performance incentive will not be included in the ROE applicable to any rate adjustment clauses.

In December 2011, Virginia Power filed a petition with the Virginia Commission seeking rehearing or reconsideration of the Biennial Review Order, to confirm the effective date of the newly authorized 10.9% base ROE. Virginia Power's petition requested the Virginia Commission to confirm that the 10.9% ROE authorized in the Biennial Review Order would apply prospectively, effective following the date of the Biennial Review Order on November 30, 2011, and that Virginia Power's previously-approved 11.9% base ROE authorized in the Virginia Settlement Approval Order would be used to measure base rate earnings for the period January 1, 2011 through November 30, 2011. In March 2012, the Virginia Commission issued an order denying Virginia Power's petition seeking rehearing or reconsideration. Contrary to Virginia Power's position, the Virginia Commission ruled that the new 10.9% ROE will be used to measure earnings for the entire 2011-2012 test period in the next biennial review in 2013, which is expected to be filed in March 2013.

Also in March 2012, Virginia Power filed Petitions for Appeal with the Supreme Court of Virginia regarding the Biennial Review Order and the March 2012 Order. In May 2012, the Supreme Court of Virginia granted review of Virginia Power's appeals from the Biennial Review Order and the March 2012 Order denying Virginia Power's petition seeking rehearing or reconsideration, and heard oral argument on both appeals in September 2012. In November 2012, the Supreme Court of Virginia affirmed the Biennial Review Order and the March 2012 Order denying Virginia Power's petition seeking rehearing or reconsideration.

ROE Applicable to Riders C1, C2, R, and S

Effective December 1, 2011, the ROE applicable to Riders C1 and C2 is 10.4%. For Riders R and S, effective December 1, 2011, the ROE is 11.4%, inclusive of a statutory enhancement of 100 basis points.

Earned Return for 2009 and 2010

The Virginia Commission determined that Virginia Power earned an ROE of approximately 13.3% during the 2009 and 2010 combined test years, which exceeded the authorized ROE earnings band of 11.4% to 12.4% established in the Virginia Settlement Approval Order. Based on the determination that Virginia Power had excess earnings, the Virginia Commission ordered Virginia Power to refund 60% of earnings above the upper end of the authorized ROE earnings band, or approximately $78 million, to its customers, which was provided in the form of credits to customers' bills amortized over a six-month period during 2012. A charge for the refund was recognized in operating revenues in the 2011 Consolidated Statement of Income. The actual aggregate refund amount totaled approximately $81 million, taking into account refunds to be paid to certain non-jurisdictional customers pursuant to their customer contracts.

Base Rates and Existing Riders T, C1, and C2

As a result of the Virginia Commission's determination that credits will be applied to customers' bills, the Virginia Commission, as required by the Regulation Act, directed Virginia Power to combine its existing Riders T, C1, and C2 with Virginia Power's base costs, revenues and investments, and to file revised tariffs reflecting such combination pursuant to the Biennial Review Order. These Riders will thereafter be considered part of Virginia Power's base costs, revenues and investments for purposes of future biennial review proceedings.

In April 2012, the Virginia Commission held that Riders C1 and C2 are now to be combined in Virginia Power's base rates and are to be considered as part of its future biennial reviews. The Virginia Commission rejected Virginia Power's requests to identify and separately track the revenues for these existing riders in base rates, and to preserve deferral accounting for these revenues in base rates, stating that such deferral accounting ceased December 1, 2011 for existing Riders C1 and C2.

In August 2012, the Virginia Commission confirmed that existing Rider T had been combined in base rates, and ruled that transmission costs would continue to be tracked separately to permit deferral accounting and dollar-for-dollar recovery of costs through Rider T and through Rider T1, a new increment/decrement rate adjustment clause to recover the difference in the revenue requirement for rate year costs and the revenues collected under Rider T.

Earnings Test Adjustments

The Virginia Commission ruled on numerous contested proposals to adjust Virginia Power's earnings for the 2009 and 2010 combined test periods. Among other adjustments, the Virginia Commission approved Virginia Power's ratemaking treatment of fuel inventories held by its wholly-owned subsidiaries. As a result of this finding, Virginia Power included in rate base approximately $188 million in fuel inventory costs for 2010. The Virginia Commission also adopted Virginia Power's treatment that includes, for regulatory earnings purposes, its AIP and LTIP expenses up to a 100% payout ratio. The Virginia Commission excluded from expense approximately $21 million in incentive plan costs that exceeded a payout ratio of 100%, allowing a net recovery of approximately $95 million of incentive compensation expense for the biennial review period. The Virginia Commission denied Virginia Power's ratemaking treatment that expensed the entire cost of its 2010 voluntary separation plan in 2010, ruling instead to amortize the cost through the end of 2011. This matched the costs of the plan with the period of realization of savings, which reduced 2010 operating costs (and in turn, increased 2011 operating costs) by approximately $103 million for purposes of the earnings test. Other than influencing the amount earned above the authorized ROE earnings band, the earnings test adjustments above did not have an impact to the Consolidated Financial Statements.

In addition, the Virginia Commission required Virginia Power to recognize a gain, for purposes of the earnings test, of approximately $44 million on the settlement of certain interest rate hedging contracts in 2010, as opposed to amortizing the gains over the forecasted term of planned debt instruments that were not issued. Virginia Power determined that it was no longer probable that these derivative gains would be included in future base rates as the Virginia Commission would not allow the amortization of these amounts in future periods.  As a result, Virginia Power removed approximately $50 million in December 2011 from regulatory liabilities and recognized the deferred derivative settlement gains in interest and related charges in the Consolidated Statements of Income.

Virginia Fuel Expenses

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

Generation Riders R and S

In connection with the Bear Garden and Virginia City Hybrid Energy Center projects, in March 2011, the Virginia Commission approved annual updates for Riders R and S with revenue requirements of $78 million and $199 million, respectively, for the April 1, 2011 to March 31, 2012 rate year, utilizing the 12.3% placeholder ROE (inclusive of a 100 basis point statutory enhancement) pending the Virginia Commission's ROE determination in the 2011 biennial review.

In March 2012, the Virginia Commission approved annual updates for Riders R and S for the April 1, 2012 to March 31, 2013 rate year, utilizing an 11.4% ROE (inclusive of a 100 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order. The Virginia Commission's approvals authorized an approximately $74 million revenue requirement for Rider R, and an approximately $226 million revenue requirement for Rider S, comprised of approximately $52 million for the pre-commercial operation period and approximately $174 million for the commercial operation period.

In June 2012, Virginia Power requested Virginia Commission approval of its annual updates for Riders R and S for the next two consecutive rate years, utilizing an 11.4% ROE (inclusive of a 100 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order and subject to true-up based on changes in the authorized ROE in future biennial review proceedings. For Rider R, Virginia Power proposed an approximately $81 million revenue requirement for the rate year beginning April 1, 2013 and an approximately $75 million revenue requirement for the rate year beginning April 1, 2014. For Rider S, an approximately $249 million revenue requirement was proposed for the rate year beginning April 1, 2013 and an approximately $229 million revenue requirement was proposed for the rate year beginning April 1, 2014. Virginia Power has agreed to certain adjustments supported by Virginia Commission Staff reducing the Rider R revenue requirements to approximately $78 million for the rate year beginning April 1, 2013, and approximately $72 million for the rate year beginning April 1, 2014. In February 2013, the Virginia Commission approved these cost recovery periods and amounts for Rider R, as well as a multi-year approach in which Virginia Power would file its next update filing for Rider R in 2014. In January 2013, Virginia Power filed a proposed stipulation agreement reached with the Virginia Commission Staff supporting a revised revenue requirement for Rider S of approximately $248 million for the rate year beginning April 1, 2013. Virginia Power and the Staff of the Virginia Commission also agreed that Virginia Power would file a Rider S case in 2013 instead of a multi-year approach. The Rider S update proceeding is pending. Construction of the Virginia City Hybrid Energy Center was completed and the facility commenced commercial operations in July 2012.

DSM Riders C1A and C2A

In April 2012, the Virginia Commission approved a revenue requirement of $5 million for Rider C1A and $17 million for Rider C2A. This approval incorporated four new energy efficiency DSM programs as a bundle for residential customers for a five-year period starting June 1, 2012, subject to a total $90 million cost cap. The Virginia Commission also approved two new energy efficiency DSM programs as a bundle for commercial customers for the same five-year period, subject to a total $45 million cost cap, as well as a new peak-shaving DSM program for commercial customers for the same five-year period, subject to an approximately $14 million cost cap.

In August 2012, Virginia Power requested extension of two DSM programs (the Residential Air Conditioner Cycling Program and the Residential Low Income Program) by five years and two years, respectively, beyond their current April 30, 2013 termination date, as well as approval of a process whereby the Staff could administratively approve limited modifications to the designs of previously approved DSM programs. Virginia Power's proposed revenue requirements for Riders C1A and C2A for the May 1, 2013 to April 30, 2014 rate year are $4 million and $23 million, respectively. This case is pending.

Transmission Riders T and T1

In May 2011, Virginia Power filed its annual update to Rider T with the Virginia Commission. The proposed $481 million annual revenue requirement, effective September 1, 2011, represented an increase of approximately $144 million over the revenue requirement associated with the Rider T customer rates previously in effect. In July 2011, the Virginia Commission issued an order approving a revenue requirement of $466 million for the September 1, 2011 to August 31, 2012 rate year. As discussed above, previously implemented Rider T will be considered part of Virginia Power's base costs, revenues and investments for purposes of future biennial review proceedings. The Virginia Commission has initiated a proceeding to address further implementation of this directive.

In May 2012, Virginia Power filed Rider T1 with the Virginia Commission to recover costs of transmission service and demand response programs for the September 1, 2012 to August 31, 2013 rate year. The proposed Rider T1 reduction of approximately $100 million produces a total annual revenue requirement of approximately $373 million when netted with the revenue requirement of approximately $473 million associated with the Rider T customer rates currently in effect, and now combined in Virginia Power's base rates. Virginia Power's filing stated that Rider T costs combined in base rates should be identified and separately tracked, with the continuation of deferral accounting and dollar-for-dollar recovery for these costs. Virginia Power's proposed revenue requirement was supported by the Staff of the Virginia Commission, although the Staff concurrently proposed an alternative methodology for the Rider T1 revenue requirement which would represent an increase of approximately $18 million from the current Rider T customer rates. The Staff's alternative methodology would have precluded deferral accounting and dollar-for-dollar recovery for Rider T in future periods.

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

Generation Rider W

In May 2011, Virginia Power requested approval from the Virginia Commission to construct and operate Warren County, as well as approval of Rider W. In February 2012, the Virginia Commission approved Certificates of Public Convenience and Necessity for Warren County and related transmission facilities. The Virginia Commission also approved a revenue requirement of $34 million for the April 1, 2012 to March 31, 2013 rate year, reflecting an ROE of 11.4%, inclusive of a statutory enhancement of 100 basis points for Rider W, consistent with the Biennial Review Order. In addition, the Virginia Commission approved an ROE enhancement of 100 basis points for Rider W for a period of 10 years following commercial operations. The facility is expected to start commercial operations in late 2014.

In June 2012, Virginia Power requested Virginia Commission approval of its annual update for Rider W for the April 1, 2013 to March 31, 2014 rate year. Virginia Power proposed an approximately $86 million revenue requirement, utilizing an 11.4% ROE (inclusive of a 100 basis point statutory enhancement) also consistent with the base ROE authorized in the Biennial Review Order. In December, 2012, Virginia Power filed a proposed partial stipulation agreement reached with the Virginia Commission Staff supporting a revised revenue requirement for Rider W of approximately $83 million for the rate year commencing April 1, 2013. In February 2013, the Virginia Commission approved this revised revenue requirement.

Generation Rider B

In June 2011, Virginia Power filed applications with the Virginia Commission seeking regulatory approval to convert three of its coal-fired power stations to biomass. The applications included a request for approval of Rider B. To qualify for federal production tax credits associated with renewable energy generation, the power stations must commence operation as biomass generation facilities by December 31, 2013. Virginia Power requested Virginia Commission approval of the biomass conversions on a schedule that will enable qualification for these tax credits.

In March 2012, the Virginia Commission approved the conversion of the Altavista, Hopewell, and Southampton power stations to biomass. These conversions will increase Dominion's renewable generation by more than 150 MW and are expected to be completed by the end of 2013.

As part of its approval, the Virginia Commission also approved Rider B. The approved revenue requirement for Rider B is approximately $6 million for the April 1, 2012 to March 31, 2013 rate year, utilizing a 12.4% ROE (inclusive of a 200 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order. The renewable generating unit statutory enhancement of 200 basis points will apply during construction and the first five years of the service lives of the converted facilities.

In June 2012, Virginia Power requested Virginia Commission approval of its annual update for Rider B for the April 1, 2013 to March 31, 2014 rate year. Virginia Power proposed an approximately $12 million revenue requirement, utilizing a 12.4% ROE (inclusive of a 200 basis point statutory enhancement) consistent with the base ROE authorized in the Biennial Review Order. In January 2013, Virginia Power filed a proposed stipulation agreement reached with the Virginia Commission Staff supporting approval of a revenue requirement for the pre-commercial operations date period and the post-commercial operations date period, resulting in an average recovery amount of approximately $12 million for the rate year commencing April 1, 2013. This case is pending.

Brunswick County Power Station and Generation Rider BW

In November 2012, Virginia Power requested approval from the Virginia Commission to construct and operate Brunswick County. The application included a request for approval of associated transmission facilities and Rider BW. Virginia Power's proposed revenue requirement for Rider BW is approximately $45 million for the September 1, 2013 to August 31, 2014 rate year, reflecting an ROE of 11.4%, inclusive of a statutory enhancement of 100 basis points for Rider BW, consistent with the Biennial Review Order. Virginia Power requested an ROE enhancement of 100 basis points for Rider BW for a period of 15 years following commercial operations. The facility is expected to begin commercial operations in spring 2016. This case is pending.

Bremo Power Station

In August 2012, Virginia Power requested approval from the Virginia Commission of an amended and reissued Certificate of Public Convenience and Necessity that would allow Virginia Power to convert Bremo Units 3 and 4 from coal to natural gas as their fuel source. The proposed conversion would preserve 227 MW (net) of existing capacity and is expected to be complete in 2014. Cost recovery would occur through base rates, and not through a rate adjustment clause. This case is pending.

Solar Distributed Generation Demonstration Program

In October 2011, Virginia Power filed with the Virginia Commission an application to conduct a solar distributed generation demonstration program, consisting of up to a combined 30 MW of Company-owned solar distributed generation facilities to be located at selected commercial, industrial and community locations throughout its Virginia service territory. Virginia Power proposed to construct and operate the Company-owned facilities in two phases, with Phase I (up to 10 MW) from the date of approval through the end of 2013 and Phase II (up to 20 MW) from the beginning of 2014 to the end of 2015. Virginia Power did not seek a rate adjustment clause for Phase I facilities with this filing; Phase I costs will be recovered as part of base rates in a future biennial review. Virginia Power indicated that it may seek a rate adjustment clause at a future time for Phase II costs.

In November 2012, the Virginia Commission approved the voluntary solar distributed generation demonstration program for Company-owned solar distributed generation facilities subject to a total cost cap of $80 million (including capital, financing, and operation and maintenance costs) which can be increased subject to future application based upon program experience, results, and data.

In May 2012, Virginia Power filed with the Virginia Commission a petition to implement a special tariff for a combined 3 MW of customer-owned solar distributed generation facilities. Under the proposed tariff, Rate Schedule SP, Virginia Power would purchase 100% of the energy output from these facilities, including all environmental attributes and associated renewable energy credits, at a fixed price of $0.15 per kWh for five years. As proposed, the costs of the purchases under Rate Schedule SP would not be recovered from all customers. Following comments, the Virginia Commission issued an order in November 2012 setting this matter for public hearing in February 2013. This case is pending.

Electric Transmission Projects

Portions of the Mt. Storm-to-Doubs line and certain associated facilities are approaching the end of their expected service lives and require replacement with new facilities to maintain reliable service. Virginia Power owns, and has been designated by PJM to rebuild, 96 miles of the line in West Virginia and Virginia, and The Potomac Edison Company owns, and has been designated by PJM to rebuild, the remaining three miles of the line in Maryland. In September 2011, the Virginia Commission approved Virginia Power's application to rebuild its portion of the Mt. Storm-to-Doubs line. The approval of the West Virginia Commission was not required. Subject to applicable state and federal regulatory approvals, Virginia Power's portion of the rebuild project is expected to be completed by June 2015.

In June 2010, the Virginia Commission authorized the construction of the Hayes-to-Yorktown line along the proposed eight-mile route utilizing existing easements and property previously acquired for the transmission line right-of-way. The Hayes-to-Yorktown line was placed in service in December 2012.

In July 2010, the Virginia Commission authorized Virginia Power to construct the Radnor Heights Project.  The Virginia Commission stated that these lines and substation must be constructed and in service by June 30, 2012, and that Virginia Power could apply to extend this date for good cause shown.  In October 2012, the Virginia Commission issued an order extending this construction and the in-service date to July 31, 2013.

In January 2012, the Virginia Commission authorized the replacement at higher voltage of approximately 43 miles of existing transmission lines between the Dooms and Bremo substations. The Dooms-to-Bremo line is expected to be completed by May 2014.

In December 2011, Virginia Power submitted an application to the Virginia Commission for approval of the Waxpool-Brambleton-BECO line. This project is required to provide requested service to a new data center campus in Loudoun County, Virginia. In December 2012, PJM authorized the Waxpool-Brambleton-BECO line as part of the 2012 RTEP and the Virginia Commission authorized construction of the line. In January 2013, a notice of appeal was filed with the Supreme Court of Virginia by a private party regarding the December 2012 Order. Subject to the receipt of applicable state and federal regulatory approvals, the Waxpool-Brambleton-BECO line is expected to be completed by November 2013.

In June 2012, Virginia Power requested Virginia Commission approval of the Surry-to-Skiffes Creek-to-Whealton lines. Subject to the receipt of applicable state and federal regulatory approvals, the Surry-to-Skiffes Creek-to-Whealton lines are expected to be completed by May 2015. Virginia Power also presented for the Virginia Commission's consideration an approximately 37 mile alternate route for the 500 kV line from Virginia Power's existing Chickahominy Substation to the proposed Skiffes Creek Switching Station.

In August 2012, Virginia Power requested Virginia Commission approval of the Harrisonburg-to-Endless Caverns line. In December 2012, the Virginia Commission authorized construction of the new line. Subject to the receipt of applicable state and federal regulatory approvals, the Harrisonburg-to-Endless Caverns line is expected to be completed by May 2015.

In November 2012, Virginia Power submitted an application to the Virginia Commission for approval to rebuild the Dooms-to-Lexington line in Virginia. Portions of the Dooms-to-Lexington line and certain associated facilities are approaching the end of their expected service lives and require replacement with new facilities to maintain reliable service. Virginia Power owns and has been designated by PJM as part of the 2012 RTEP to rebuild the 39 mile line in Rockbridge and Augusta Counties, Virginia. Subject to applicable state and federal regulatory approvals, the rebuild project is expected to be completed by May 2016.

North Anna Power Station

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. However, Virginia Power has not yet committed to building a new nuclear unit at North Anna and continues to evaluate its options regarding a new nuclear unit.

If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power has applied for and continues to pursue the COL from the NRC. Based on the current NRC schedule, the COL is expected no earlier than late 2015. Virginia Power also continues to pursue engineering and preliminary site development work, in addition to holding an Early Site Permit.  In December 2011, Virginia Power acquired ODEC's interest in the project, thereby terminating ODEC's involvement in the development of a potential third unit at North Anna. In January 2013, the NRC approved the transfer of ODEC's interest in the Early Site Permit to Virginia Power.

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. In April 2011, BREDL's then last remaining contention was dismissed by the ASLB, and following a decision by the NRC in June 2012, subsequently resulted in termination of the contested portion of the proceeding. 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, with the consent of BREDL and the NRC staff to hold any ruling on this proposed contention in abeyance until Virginia Power completes an assessment of this earthquake. The NRC's June 2012 decision referred this new proposed contention to the ASLB to consider whether the contested portion of the proceeding should be reopened. In July 2012, the ASLB granted BREDL a period of 60 days to submit a motion to reopen the proceeding from the time Virginia Power informs the NRC and parties that its seismic assessment is complete.

In addition, in June 2012, BREDL filed a petition with the NRC seeking to suspend the COL proceeding based on a June 2012 ruling of the U.S. Court of Appeals for the District of Columbia Circuit reversing and remanding a 2010 NRC rulemaking that generically assessed the environmental impacts of spent fuel storage. Virginia Power opposed the petition. In July 2012, BREDL filed a motion with the NRC to reopen the contested portion of the COL proceeding to admit a contention pertaining to the same subject. Substantially identical suspension petitions and contentions were filed by various intervenor groups in other licensing proceedings pending before the NRC. In August 2012, the NRC issued a memorandum and order applicable to all pending licensing proceedings, including the North Anna COL proceeding. The NRC indicated that final licenses would not be issued until the issues raised in the court's decision had been addressed. The NRC indicated that this determination extends only to final license issuance and that all licensing reviews and proceedings should continue to move forward. The NRC also directed that pending contentions on the topic be held in abeyance pending further NRC order. The NRC's August 2012 decision is not expected to affect the schedule for issuance of the COL.

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. Virginia Power continues to pursue various environmental permits that would be needed to support future construction and operation of a third nuclear unit at North Anna.

North Carolina Regulation

In December 2011, the North Carolina Commission issued an order approving a settlement agreement among Virginia Power, the Public Staff of the North Carolina Commission and other interested parties in Virginia Power's fuel case for its North Carolina service territory. The settlement agreement provided for a $36 million increase in Virginia Power's fuel revenues for one year, effective January 1, 2012, including approximately $13 million in under recovery of fuel expenses for the previous fuel period.

In March 2012, Virginia Power filed an application with the North Carolina Commission to increase base non-fuel revenues by approximately $64 million, with January 1, 2013 as the proposed effective date for the permanent rate revision.

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

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

In December 2012, the North Carolina Commission approved a $36 million increase in Virginia Power's annual non-fuel base revenues, based on an authorized ROE of 10.2%, and a $14 million decrease in annual base fuel revenues for a combined total base revenue increase of $22 million. These rate changes became effective on January 1, 2013 and are being appealed to the North Carolina Supreme Court by multiple parties. In December 2012, Virginia Power established net regulatory assets of $17 million to be recovered over five to ten years in connection with these new rates.

Also, in December 2012, the North Carolina Commission approved a $17 million decrease in Virginia Power's annual non-base fuel Experience Modification Factor revenues. The rate decrease is the result of the Commission's approval of the Fuel-Related Stipulation of Settlement between the Public Staff and Virginia Power. The rate change was approved by the Commission after review of Virginia Power's fuel expenses during the 12-month period ended June 30, 2012, and represents changes experienced by Virginia Power with respect to its reasonable costs of fuel and fuel component of purchased power.

Ohio Regulation

PIR Program

In March 2011, East Ohio filed a request with the Ohio Commission to accelerate the PIR program by nearly doubling its PIR spending to more than $200 million annually. East Ohio identified 1,450 miles of pipeline that need to be replaced, in addition to the pipeline originally identified in the PIR project scope. East Ohio plans to accelerate the pace of the program by investing more resources in its infrastructure in the near term, in an effort to promote ongoing public safety and reduce operating costs over the longer term. In August 2011, the Ohio Commission approved the stipulation by East Ohio, the Staff of the Ohio Commission and other interested parties 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 February 2012, East Ohio submitted an application with the Ohio Commission to adjust the cost recovery charge for costs associated with PIR investments for the six months ended December 31, 2011. The filing was made in accordance with changes to the PIR program approved by the Ohio Commission in August 2011 and effects a transition from a fiscal year ending June 30 to a calendar year for annual filings thereafter. The application includes total gross plant investment for the six-month July 1-December 31, 2011 transition period of $73 million, cumulative gross plant investment of $362 million, and a revenue requirement of $47 million. A stipulation was submitted by East Ohio, the Staff of the Ohio Commission and the Ohio Consumers' Counsel that supports the rates filed by East Ohio. The Ohio Commission issued an order approving the stipulation in April 2012.

In November 2012, East Ohio filed a notice to adjust the PIR Cost Recovery Charge for 2012 costs. East Ohio expects to file its application to adjust the PIR Recovery Charge in the first quarter of 2013.

PIPP Plus Program

Under the Ohio PIPP Plus program, eligible customers can receive energy assistance based on their ability to pay their bill. The difference between the customer's total bill and the PIPP plan payment amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. The PIPP Plus program sets the customer's monthly payments at 6% of household income and provides for forgiveness credits to the customer's balance when required payments are received in full by the due date. Such credits may result in the elimination of the customer's arrearage balance over 24 months.

In July 2012, the Ohio Commission approved East Ohio's annual update of the PIPP Rider, which reflects the refund of an over-recovery of accumulated arrearages of approximately $70 million over the next two years and recovery of projected deferred program costs of approximately $104 million for the 12-month period from April 2012 to March 2013.

UEX Rider

East Ohio files an annual UEX Rider with the Ohio Commission, pursuant to which it seeks recovery of the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar-for-dollar recovery of East Ohio's actual write-offs of uncollectable amounts.

In July 2012, the Ohio Commission approved East Ohio's annual update of the UEX Rider, which reflects the elimination of accumulated unrecovered bad debt expense of approximately $1 million as of March 31, 2012, and recovery of prospective bad debt expense projected to total approximately $23 million for the 12-month period from April 2012 to March 2013.

House Bill 95

Ohio enacted utility reform legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future. In December 2011, East Ohio filed an application requesting authority to implement a capital expenditure program under the new law, which, if approved, would enable East Ohio to defer as a regulatory asset carrying costs, depreciation and property tax associated with approximately $95 million in capital expenditures incurred between October 2011 and December 2012 for assets placed in service but not yet reflected in rates. The Ohio Commission approved East Ohio's application in December 2012.

In December 2012, East Ohio filed an application requesting authority to implement a capital expenditure program for 2013 capital expenditures totaling $93 million, subject to the provisions approved for the initial application. This case is pending.

Federal Regulation

FERC - Gas

FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion's interstate natural gas company subsidiaries, including DTI and Cove Point. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

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

XML

Investments

12 Months Ended

Dec. 31, 2012

Investments, Debt and Equity Securities [Abstract]

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 $95 million and $90 million at December 31, 2012 and 2011, respectively. Cost-method investments held in Dominion's rabbi trusts totaled $14 million and $17 million at December 31, 2012 and 2011, 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)
2012
Marketable equity securities:
U.S.:
Large Cap	$	1,210	$	732	$	—			$	1,942
Other	40		13		—				53
Marketable debt securities:
Corporate debt instruments	295		30		—				325
U.S. Treasury securities and agency debentures	523		19		(2		)		540
State and municipal	248		26		—				274
Other	6		1		—				7
Cost method investments	117		—		—				117
Cash equivalents and other(2)	72		—		—				72
Total	$	2,511	$	821	$	(2	)	(3)	$	3,330
2011
Marketable equity securities:
U.S.:
Large Cap	$	1,152	$	537	$	—			$	1,689
Other	36		10		—				46
Marketable debt securities:
Corporate debt instruments	314		19		(1		)		332
U.S. Treasury securities and agency debentures	437		20		(1		)		456
State and municipal	264		24		—				288
Other	23		1		—				24
Cost method investments	118		—		—				118
Cash equivalents and other(2)	46		—		—				46
Total	$	2,390	$	611	$	(2	)	(3)	$	2,999

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

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

(3) The fair value of securities in an unrealized loss position was $195 million and $164 million at December 31, 2012 and 2011, respectively.

The fair value of Dominion's marketable debt securities held in nuclear decommissioning trust funds at December 31, 2012 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	116
Due after one year through five years	304
Due after five years through ten years	357
Due after ten years	369
Total	$	1,146

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

Year Ended December 31,	2012		2011		2010
(millions)
Proceeds from sales	$	1,356	$	1,757	$	1,814	(1)
Realized gains(2)	98		79		111
Realized losses(2)	33		92		63

(1) Does not include $1 billion of proceeds reflected in Dominion's Consolidated Statement of Cash Flows from the sale of temporary investments consisting of time deposits and Treasury Bills, purchased following the sale of substantially all of Dominion's Appalachian E&P operations.

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

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

Year Ended December 31,	2012			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	26		$	75		$	59
Losses recorded to decommissioning trust regulatory liability	(10		)	(24		)	(21		)
Losses recognized in other comprehensive income (before taxes)	(2		)	(3		)	(3		)
Net impairment losses recognized in earnings	$	14		$	48		$	35

(1) Amounts include other-than-temporary impairment losses for debt securities of $4 million, $6 million and $10 million at December 31, 2012, 2011 and 2010, respectively.

Equity Method Investments

Investments that Dominion accounts for under the equity method of accounting are as follows:

Company	Ownership%		Investment Balance				Description
As of December 31,			2012		2011
(millions)
Fowler I Holdings LLC	50	%	$	158	$	166	Wind-powered merchant generation facility
NedPower Mount Storm LLC	50	%	137		146		Wind-powered merchant generation facility
Elwood Energy LLC	50	%	117		108		Natural gas-fired merchant generation peaking facility
Iroquois Gas Transmission System, LP	24.72	%	102		104		Gas transmission system
Blue Racer Midstream LLC	50	%	39		—		Midstream gas and related services
Other(1)	various		5		29
Total			$	558	$	553

(1) Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018.

Dominion's equity earnings on these investments totaled $25 million, $35 million and $42 million in 2012, 2011 and 2010, respectively. Dominion received distributions from these investments of $58 million, $55 million and $60 million in 2012, 2011, and 2010, respectively. As of December 31, 2012 and 2011, the carrying amount of Dominion's investments exceeded Dominion's share of underlying equity in net assets by approximately $30 million and $32 million, respectively. The differences relate to Dominion's investments in wind projects and primarily reflect its capitalized interest during construction and the excess of its cash contributions over the book value of development assets contributed by Dominion's partners for these projects. The differences are generally being amortized over the useful lives of the underlying assets.

BLUE RACER

In December 2012, Dominion formed a joint venture with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. The joint venture, Blue Racer, is an equal partnership between Dominion and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital.  In return for its December 2012 contribution of assets to the joint venture, Dominion received a 50% interest in Blue Racer and received $115 million in cash proceeds, resulting in a gain of $72 million ($43 million after-tax), net of transaction fees of $9 million, which is recorded in other operations and maintenance expense in Dominion's Consolidated Statement of Income. The joint venture will leverage Dominion's existing presence in the Utica region with significant additional new capacity designed to meet producer needs as the Utica Shale acreage is developed. Midstream services offered will include gathering, processing, fractionation, and NGL transportation and marketing. In addition to the assets already contributed, Dominion expects to contribute additional gathering assets, the Natrium extraction plant and related NGL pipeline, and a DTI pipeline connecting East Ohio's gathering system to Natrium. 

VIRGINIA POWER

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

	Amortized Cost		Total Unrealized Gains (1)		Total Unrealized Losses (1)				Fair Value
(millions)
2012
Marketable equity securities:
U.S.:
Large Cap	$	481	$	298	$	—			$	779
Other	20		7		—				27
Marketable debt securities:
Corporate debt instruments	179		17		—				196
U.S. Treasury securities and agency debentures	231		4		(1		)		234
State and municipal	106		11		—				117
Other	1		—		—				1
Cost method investments	117		—		—				117
Cash equivalents and other(2)	44		—		—				44
Total	$	1,179	$	337	$	(1	)	(3)	$	1,515
2011
Marketable equity securities:
U.S.:
Large Cap	$	460	$	218	$	—			$	678
Other	18		5		—				23
Marketable debt securities:
Corporate debt instruments	204		11		(1		)		214
U.S. Treasury securities and agency debentures	166		4		—				170
State and municipal	114		10		—				124
Other	16		1		(1		)		16
Cost method investments	118		—		—				118
Cash equivalents and other(2)	27		—		—				27
Total	$	1,123	$	249	$	(2	)	(3)	$	1,370

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

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

(3) The fair value of securities in an unrealized loss position was $104 million and $99 million at December 31, 2012 and 2011, respectively.

The fair value of Virginia Power's debt securities at December 31, 2012, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	18
Due after one year through five years	156
Due after five years through ten years	217
Due after ten years	157
Total	$	548

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

Year Ended December 31,	2012		2011		2010
(millions)
Proceeds from sales	$	626	$	1,030	$	1,192
Realized gains(1)	42		34		52
Realized losses(1)	11		34		23

(1) Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2.

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

Year Ended December 31,	2012			2011			2010
(millions)
Total other-than-temporary impairment losses(1)	$	11		$	29		$	25
Losses recorded to decommissioning trust regulatory liability	(10		)	(24		)	(21		)
Losses recorded in other comprehensive income (before taxes)	—			(1		)	(1		)
Net impairment losses recognized in earnings	$	1		$	4		$	3

(1) Amounts include other-than-temporary impairment losses for debt securities of $2 million, $4 million and $6 million at December 31, 2012, 2011 and 2010, respectively.

OTHER INVESTMENTS

Dominion and Virginia Power hold restricted cash and cash equivalent balances that primarily consist of money market fund investments held in trust for the purpose of funding certain qualifying construction projects. At December 31, 2012 and 2011, Dominion had $37 million and $147 million, respectively, and Virginia Power had $10 million and $32 million, respectively, of restricted cash and cash equivalents. These balances are presented in Other Current Assets and Investments in the Consolidated Balance Sheets.

XML

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, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Investment Holdings [Line Items]
Total amortized cost basis	$ 2,511		$ 2,390
Total Unrealized Gains	821	[1]	611	[1]
Total Unrealized Losses	(2)	[1],[2]	(2)	[1],[2]
Fair Value	3,330		2,999
Net assets related to pending sales and purchases of securities	6		11
Fair value of securities in an unrealized loss position	195		164
Cost method investments
Investment Holdings [Line Items]
Other investments and securities, at cost	117		118
Total Unrealized Gains	0	[1]	0	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	117		118
Cash equivalents and other
Investment Holdings [Line Items]
Other investments and securities, at cost	72	[3]	46	[3]
Total Unrealized Gains	0	[1],[3]	0	[1],[3]
Total Unrealized Losses	0	[1],[3]	0	[1],[3]
Fair Value	72	[3]	46	[3]
Equity securities: | Large Cap | U.S.:
Investment Holdings [Line Items]
Amortized Cost	1,210		1,152
Total Unrealized Gains	732	[1]	537	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	1,942		1,689
Equity securities: | Other | U.S.:
Investment Holdings [Line Items]
Amortized Cost	40		36
Total Unrealized Gains	13	[1]	10	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	53		46
Corporate debt instruments
Investment Holdings [Line Items]
Amortized Cost	295		314
Total Unrealized Gains	30	[1]	19	[1]
Total Unrealized Losses	0	[1]	(1)	[1]
Fair Value	325		332
U.S. Treasury securities and agency debentures
Investment Holdings [Line Items]
Amortized Cost	523		437
Total Unrealized Gains	19	[1]	20	[1]
Total Unrealized Losses	(2)	[1]	(1)	[1]
Fair Value	540		456
State and municipal
Investment Holdings [Line Items]
Amortized Cost	248		264
Total Unrealized Gains	26	[1]	24	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	274		288
Other
Investment Holdings [Line Items]
Amortized Cost	6		23
Total Unrealized Gains	1	[1]	1	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	7		24
Virginia Electric and Power Company
Investment Holdings [Line Items]
Total amortized cost basis	1,179		1,123
Total Unrealized Gains	337	[1]	249	[1]
Total Unrealized Losses	(1)	[1],[4]	(2)	[1],[4]
Fair Value	1,515		1,370
Net assets related to pending sales and purchases of securities	6		13
Fair value of securities in an unrealized loss position	104		99
Virginia Electric and Power Company | Cost method investments
Investment Holdings [Line Items]
Other investments and securities, at cost	117		118
Total Unrealized Gains	0	[1]	0	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	117		118
Virginia Electric and Power Company | Cash equivalents and other
Investment Holdings [Line Items]
Other investments and securities, at cost	44	[5]	27	[5]
Total Unrealized Gains	0	[1],[5]	0	[1],[5]
Total Unrealized Losses	0	[1],[5]	0	[1],[5]
Fair Value	44	[5]	27	[5]
Virginia Electric and Power Company | Equity securities: | Large Cap | U.S.:
Investment Holdings [Line Items]
Amortized Cost	481		460
Total Unrealized Gains	298	[1]	218	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	779		678
Virginia Electric and Power Company | Equity securities: | Other | U.S.:
Investment Holdings [Line Items]
Amortized Cost	20		18
Total Unrealized Gains	7	[1]	5	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	27		23
Virginia Electric and Power Company | Corporate debt instruments
Investment Holdings [Line Items]
Amortized Cost	179		204
Total Unrealized Gains	17	[1]	11	[1]
Total Unrealized Losses	0	[1]	(1)	[1]
Fair Value	196		214
Virginia Electric and Power Company | U.S. Treasury securities and agency debentures
Investment Holdings [Line Items]
Amortized Cost	231		166
Total Unrealized Gains	4	[1]	4	[1]
Total Unrealized Losses	(1)	[1]	0	[1]
Fair Value	234		170
Virginia Electric and Power Company | State and municipal
Investment Holdings [Line Items]
Amortized Cost	106		114
Total Unrealized Gains	11	[1]	10	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	117		124
Virginia Electric and Power Company | Other
Investment Holdings [Line Items]
Amortized Cost	1		16
Total Unrealized Gains	0	[1]	1	[1]
Total Unrealized Losses	0	[1]	(1)	[1]
Fair Value	$ 1		$ 16

[1] Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

[2] The fair value of securities in an unrealized loss position was $195 million and $164 million at December 31, 2012 and 2011, respectively.

[3] Includes pending purchases of securities of $6 million and $11 million at December 31, 2012 and 2011, respectively.

[4] The fair value of securities in an unrealized loss position was $104 million and $99 million at December 31, 2012 and 2011, respectively.

[5] Includes pending sales of securities of $6 million and pending purchases of securities of $13 million at December 31, 2012 and 2011, respectively

XML

Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Expense (Benefit) [Abstract]

Income Taxes

INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. Dominion and Virginia Power are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

On January 2, 2013, U.S. federal legislation was enacted that provides an extension of the 50 percent bonus depreciation allowance for qualifying capital expenditures incurred through 2013.

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

Changes in tax treatment elected by Dominion or required by the regulations will impact income taxes payable, cash flows from operations and deferred taxes. Except to the extent the implementation impacts deferred taxes and, therefore, the rate base used to establish customer rates for regulated utilities, results of operations are not expected to be materially affected.

Continuing Operations

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

	Dominion(1)									Virginia Power(2)
Year Ended December 31,	2012			2011			2010			2012			2011			2010
(millions)
Current:
Federal	$	(117	)	$	3		$	894		$	70		$	(35	)	$	(78	)
State	80			9			309			81			79			10
Total current expense (benefit)	(37		)	12			1,203			151			44			(68		)
Deferred:
Federal	214			694			818			482			484			537
State	(30		)	50			93			21			13			74
Total deferred expense	184			744			911			503			497			611
Amortization of deferred investment tax credits	(1		)	(2		)	(2		)	(1		)	(1		)	(1		)
Total income tax expense	$	146		$	754		$	2,112		$	653		$	540		$	542

(1) In 2012, Dominion's current federal income tax benefit includes a benefit related to the carryback of its current year operating loss, and deferred state income tax benefit reflects the impact of Brayton Point, Kincaid and Kewaunee impairment charges. In 2011, Dominion's federal income tax expense includes a benefit related to its current year operating loss that is expected to be used in future years, and state income tax expense reflects changes in the amount of income apportioned among states, higher tax credits, claims for refunds and previously unrecognized tax benefits due to the expiration of statutes of limitations.

(2) In 2011, Virginia Power's federal income tax expense includes a benefit related to a portion of its current year operating loss that is expected to be used in future years. Also, in 2011 and 2010, Virginia Power's federal income tax expense reflects the amounts of current year operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

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
Year Ended December 31,	2012		2011		2010		2012		2011		2010
U.S. statutory rate	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit	8.1		1.8		5.1		3.9		4.4		3.8
Valuation allowances	(1.5	)	—		(0.2	)	—		—		—
Production tax credits	(2.4	)	(0.6	)	(0.3	)	—		—		—
Amortization of investment tax credits	(0.3	)	(0.1	)	—		(0.1	)	(0.1	)	(0.1	)
AFUDC - equity	(4.1	)	(0.6	)	(0.4	)	(0.9	)	(0.8	)	(1.1	)
Employee stock ownership plan deduction	(3.1	)	(0.7	)	(0.3	)	—		—		—
Goodwill	0.4		—		0.9		—		—		—
Legislative change	—		—		1.1		—		—		1.1
Other, net	(2.8	)	(0.6	)	(0.2	)	0.4		1.2		0.2
Effective tax rate	29.3	%	34.2	%	40.7	%	38.3	%	39.7	%	38.9	%

Dominion's effective tax rate in 2012 reflects the amplified effect of permanent differences due to lower pre-tax income, as well as the state tax impact of Brayton Point, Kincaid and Kewaunee impairment charges. The rate also reflects a $20 million reduction of a valuation allowance related to state operating loss carryforwards attributable to Fairless and a $14 million increase in valuation allowance related to Brayton Point state credit carryforwards. After considering the results of Fairless' operations in recent years and a forecast of future operating results reflecting Dominion's planned purchase of the facility, Dominion has concluded that it is more likely than not that the tax benefit of the operating losses will be realized. Significant assumptions include future commodity prices, in particular, those for electric energy produced by Fairless and those for natural gas, as compared to other fuels used for the generation of electricity, which will significantly influence the extent to which Fairless is dispatched by PJM. Also, in connection with its intention to sell Brayton Point, Dominion evaluated state tax credits previously recognized for the power station and recorded a $14 million increase in valuation allowance related to credit carryforwards and a $14 million deferred tax liability, representing recapture of credits claimed in prior years that would result upon completion of a sale. Dominion will continue to evaluate the likelihood of realizing these tax benefits on a quarterly basis.

Dominion's and Virginia Power's effective tax rates in 2010 reflect reductions of deferred tax assets of $57 million and $17 million, respectively, 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 includes higher state income taxes and the impact of goodwill written off that is not deductible for tax purposes associated with the sale of the Appalachian E&P operations.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

The Companies' deferred income taxes consist of the following:

	Dominion						Virginia Power
At December 31,	2012			2011			2012			2011
(millions)
Deferred income taxes:
Total deferred income tax assets	$	2,505		$	2,229		$	466		$	503
Total deferred income tax liabilities	7,716			7,424			4,238			3,759
Total net deferred income tax liabilities	$	5,211		$	5,195		$	3,772		$	3,256
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	4,601		$	4,008		$	3,394		$	2,758
Nuclear decommissioning	994			913			407			374
Deferred state income taxes	474			493			265			243
Federal benefit of deferred state income taxes	(166		)	(173		)	(93		)	(85		)
Deferred fuel, purchased energy and gas costs	3			161			(16		)	144
Pension benefits	231			396			(17		)	8
Other postretirement benefits	(171		)	(167		)	(7		)	(13		)
Loss and credit carryforwards	(656		)	(577		)	(77		)	(55		)
Reserve for rate proceedings	—			(54		)	—			(54		)
Partnership basis differences	174			274			—			—
Valuation allowances	93			96			—			—
Other	(366		)	(175		)	(84		)	(64		)
Total net deferred income tax liabilities	$	5,211		$	5,195		$	3,772		$	3,256

At December 31, 2012, Dominion had the following deductible loss and credit carryforwards:

• Federal loss carryforwards of $1.1 billion that expire if unutilized during the period 2021 through 2031;

• Federal production tax credits of $26 million that expire if unutilized through 2032;

• State loss carryforwards of $1.4 billion that expire if unutilized during the period 2014 through 2032. A valuation allowance on $857 million of these carryforwards has been established;

• State minimum tax credits of $96 million that do not expire; and

• State investment tax credits of $28 million that expire if unutilized through 2016. A valuation allowance on $21 million of these credits has been established for credits that are not expected to be utilized.

At December 31, 2012, Virginia Power had federal loss carryforwards of $220 million that expire if unutilized through 2031.

Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. The amount of tax return positions that are not recognized in the financial statements is disclosed as unrecognized tax benefits. These unrecognized tax benefits may impact the financial statements by increasing income taxes payable, reducing tax refunds receivable or changing deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, an increase in taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities.

A reconciliation of changes in the Companies' unrecognized tax benefits follows:

	Dominion									Virginia Power
	2012			2011			2010			2012			2011			2010
(millions)
Balance at January 1	$	347		$	307		$	291		$	114		$	117		$	121
Increases-prior period positions	28			127			34			4			22			4
Decreases-prior period positions	(106		)	(119		)	(75		)	(80		)	(51		)	(33		)
Increases-current period positions	43			64			61			24			47			25
Decreases-current period positions	—			(21		)	—			—			(21		)	—
Settlements with tax authorities	(4		)	—			—			(4		)	—			—
Expiration of statutes of limitation	(15		)	(11		)	(4		)	(1		)	—			—
Balance at December 31	$	293		$	347		$	307		$	57		$	114		$	117

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from claims for tax benefits, or portions thereof, that may not be realized, remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitation. For Dominion and its subsidiaries, these unrecognized tax benefits were $167 million, $184 million and $133 million at December 31, 2012, 2011 and 2010, respectively. For Dominion, the change in these unrecognized tax benefits increased income tax expense by $1 million, $51 million and $38 million in 2012, 2011 and 2010, respectively. For Virginia Power, these unrecognized tax benefits were $13 million, $20 million and $14 million at December 31, 2012, 2011 and 2010, respectively. For Virginia Power, the change in these unrecognized tax benefits increased income tax expense by $1 million, $6 million and by less than $1 million in 2012, 2011 and 2010, respectively.

For Dominion and its subsidiaries, the U.S. federal statute of limitations has expired for years prior to 2008. For prior years, Dominion had reserved the right to pursue refunds related to the calculation of interest to be capitalized in connection with improvements to in-service plant and equipment for the years 1995 through 2007. The IRS position had provided that capitalized interest must also be computed on the adjusted tax basis of in-service assets that are idled while making improvements to them. In response to litigation initiated by Dominion in March 2008, the U.S. Court of Federal Claims ruled in February 2011, sustaining the IRS position. In July 2011, Dominion filed an appeal with the United States Court of Appeals for the Federal Circuit and, in May 2012, the U.S. Court of Appeals for the Federal Circuit ruled in favor of Dominion. The resolution of this matter did not have a material impact on the Companies' cash flows, results of operations or financial condition.

In January 2012, the Appellate Division of the IRS informed Dominion that the Joint Committee had completed its review of the settlement of tax years 2004 and 2005 for Dominion and its consolidated subsidiaries. Since the measurement of unrecognized tax benefits in 2011 considered the results of completed settlement negotiations, Dominion's results of operations in 2012 were not affected.

In April 2012, the IRS issued its Revenue Agent Report for Dominion's consolidated tax returns for tax years 2006 and 2007, reflecting the resolution of all issues, except the capitalized interest on idle property issue that was in litigation at that time but later resolved as discussed above.

The IRS examination of tax years 2008, 2009 and 2010 began in the first quarter of 2012 and was later expanded to include examination of the 2011 tax year. The audit is expected to be concluded in late 2013.

It is reasonably possible that settlements with and payments to tax authorities in 2013 and, the expiration of statutes of limitations, could reduce unrecognized tax benefits for Dominion and Virginia Power by up to $65 million and $35 million, respectively. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, Dominion's earnings could increase by up to $10 million, and Virginia Power's earnings would not be affected.

Otherwise, with regard to 2012 and prior years, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2013.

For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows:

State	Earliest Open Tax Year
Pennsylvania	2009
Connecticut	2009
Massachusetts	2008
Virginia(1)	2009
West Virginia	2009

(1) Virginia is the only state considered major for Virginia Power's operations.

Dominion and Virginia Power are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are subject to examination.

Discontinued Operations

Dominion's effective tax rate for 2012 reflects the dispositions of State Line and Salem Harbor.

Dominion's effective tax rate for 2011 reflects an expectation that State Line's deferred tax assets, including 2011 operating losses, will not be realized in State Line's separately filed state tax returns.

Dominion's effective tax rate for 2010 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.

XML

Significant Accounting Policies (Depreciation Rates and Estimated Useful Life) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Generation
Depreciation rates	2.62%	2.68%	2.59%
Generation | Virginia Electric and Power Company
Depreciation rates	2.62%	2.68%	2.59%
Transmission
Depreciation rates	2.17%	2.26%	2.24%
Transmission | Virginia Electric and Power Company
Depreciation rates	1.98%	2.03%	1.94%
Distribution
Depreciation rates	3.17%	3.19%	3.20%
Distribution | Virginia Electric and Power Company
Depreciation rates	3.32%	3.33%	3.33%
Storage
Depreciation rates	2.59%	2.64%	2.75%
Gas gathering and processing
Depreciation rates	2.49%	2.52%	2.39%
General and other
Depreciation rates	4.55%	4.66%	4.60%
General and other | Virginia Electric and Power Company
Depreciation rates	4.32%	4.38%	4.28%
Minimum | General and other
Property, Plant and Equipment, Useful Life	5 years
Minimum | Merchant generation-nuclear
Property, Plant and Equipment, Useful Life	34 years
Minimum | Merchant generation-other
Property, Plant and Equipment, Useful Life	27 years
Maximum | General and other
Property, Plant and Equipment, Useful Life	59 years
Maximum | Merchant generation-nuclear
Property, Plant and Equipment, Useful Life	44 years
Maximum | Merchant generation-other
Property, Plant and Equipment, Useful Life	40 years

XML

Shareholders' Equity (Summary of Changes in Amounts of Stock Options Outstanding) (Details) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding and exercisable beginning, Shares	628		1,810		3,822
Exercised, Shares	(622)		(1,174)		(1,983)
Forfeited/expired, Shares	(6)		(8)		(29)
Outstanding and exercisable ending, Shares	0		628		1,810
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Outstanding and exercisable beginning, Weighted-average Exercise Price	$ 30.81		$ 31.76		$ 31.25
Exercised, Weighted-average Exercise Price	$ 30.79		$ 32.46		$ 30.81
Forfeited/expired, Weighted-average Exercise Price	$ 32.26		$ 31.57		$ 29.84
Outstanding and exercisable ending, Weighted-average Exercise Price	$ 0.00		$ 30.81		$ 31.76
Outstanding and exercisable beginning, Weighted-average Remaining Contractual Life
Outstanding and exercisable ending, Weighted-average Remaining Contractual Life
Outstanding and exercisable beginning, Aggregated Intrinsic Value	$ 14	[1]	$ 20	[1]	$ 29	[1]
Exercised, Aggregated Intrinsic Value	13	[1]	17	[1]	22	[1]
Outstanding and exercisable ending, Aggregated Intrinsic Value	$ 0	[1]	$ 14	[1]	$ 20	[1]

[1] Intrinsic value represents the difference between the exercise price of the option and the market value of Dominion's stock.

XML

Dispositions

12 Months Ended

Dec. 31, 2012

Discontinued Operations and Disposal Groups [Abstract]

Dispositions

DISPOSITIONS

Sale of Salem Harbor and State Line

In August 2012, Dominion completed the sale of Salem Harbor. In the second quarter of 2012, the assets and liabilities to be disposed were classified as held for sale and adjusted to their estimated fair value less cost to sell. During the second quarter of 2012, Dominion completed the sale of State Line, which ceased operations in March 2012. See Note 6 for impairments related to these power stations.

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

Year Ended December 31,	2012			2011			2010
(millions)
Operating revenue	$	57		$	233		$	269
Loss before income taxes(1)	(49		)	(34		)	(158		)

(1) Includes long-lived asset impairment charges of $55 million and $194 million in 2011 and 2010, respectively.

Sale of Appalachian E&P Operations

In April 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations to a 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 includes 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 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:

Year Ended December 31,	2010
(millions)
Operating revenue	$	67
Loss before income taxes	(134		)	(1)

(1) Includes a loss and other charges related to the sale of Peoples.

XML

Operating Revenue

12 Months Ended

Dec. 31, 2012

Regulated and Unregulated Operating Revenue [Abstract]

Operating Revenue

OPERATING REVENUE

Dominion's and Virginia Power's operating revenue consists of the following:

Year Ended December 31,	2012		2011		2010
(millions)
Dominion
Electric sales:
Regulated	$	7,102	$	7,114	$	7,123
Nonregulated	2,742		3,100		3,559
Gas sales:
Regulated	250		287		308
Nonregulated	1,071		1,635		2,010
Gas transportation and storage	1,401		1,506		1,493
Other	527		503		434
Total operating revenue	$	13,093	$	14,145	$	14,927
Virginia Power
Regulated electric sales	$	7,102	$	7,114	$	7,123
Other	124		132		96
Total operating revenue	$	7,226	$	7,246	$	7,219

XML

Quarterly Financial and Common Stock Data (Unaudited) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended	3 Months Ended			12 Months Ended			3 Months Ended
	Dec. 31, 2011	Dec. 31, 2012	Sep. 30, 2012 Kewaunee	Jun. 30, 2012 Virginia Electric and Power Company	Dec. 31, 2011 Virginia Electric and Power Company	Dec. 31, 2012 Virginia Electric and Power Company	Dec. 31, 2011 Virginia Electric and Power Company	Dec. 31, 2012 Dominion Generation	Dec. 31, 2012 Brayton Point Kincaid And Elwood Power Stations Dominion Generation
Impairment charge		$ 2,100							$ 1,000
Impairment and other charges			281
Asset impairment, net of tax	139				139		139	139
Restoration costs net of tax				$ 42		$ 53	$ 59

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of Dominion's and Virginia Power's own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion and Virginia Power apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, and nuclear decommissioning trust and other investments including those held in Dominion's rabbi, pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above. These credit adjustments are currently not material to the derivative fair values.

Inputs and Assumptions

The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, they consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases they must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect their market assumptions.

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

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, the Companies generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. The Companies use other option models under special circumstances, including a Spread Approximation Model when contracts include different commodities or commodity locations and a Swing Option Model when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract's estimated fair value.

The inputs and assumptions used in measuring fair value include the following:

For commodity and foreign currency derivative contracts:

• Forward commodity prices

• Forward foreign currency prices

• Transaction prices

• Price volatility

• Volumes

• Commodity location

• Interest rates

• Credit quality of counterparties and Dominion and Virginia Power

• Credit enhancements

• Time value

For interest rate derivative contracts:

• Interest rate curves

• Credit quality of counterparties and Dominion and Virginia Power

• Volumes

• Credit enhancements

• Time value

For investments:

• Quoted securities prices and indices

• Securities trading information including volume and restrictions

• Maturity

• Interest rates

• Credit quality

• NAV (only for alternative investments)

Dominion and Virginia Power regularly evaluate and validate the inputs used to estimate fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities and investments in which the Companies transact.

Levels

The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

•Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as the majority of exchange-traded derivatives, and exchange-listed equities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion.

•Level 2-Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps, interest rate swaps, foreign currency forwards and options, restricted cash equivalents, and certain Treasury securities, money market funds, and corporate, state and municipal debt securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion.

•Level 3-Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for Dominion and Virginia Power consist of long-dated commodity derivatives, FTRs and other modeled commodity derivatives. Additional instruments categorized in Level 3 for Dominion include NGLs and natural gas peaking options and alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments, held in benefit plan trust funds.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

For derivative contracts, Dominion and Virginia Power recognize transfers among Level 1, Level 2 and Level 3 based on fair values as of the first day of the month in which the transfer occurs. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies' over-the-counter derivative contracts is subject to change.

Level 3 Valuations

Fair value measurements are categorized as Level 3 when a significant amount of price or other inputs that are considered to be unobservable are used in their valuations. Long-dated commodity derivatives are generally based on unobservable inputs due to the length of time to settlement and the absence of market activity and are therefore categorized as Level 3. For NGL derivatives, market illiquidity requires a valuation based on proxy markets that do not always correlate to the actual instrument, therefore they are categorized as Level 3. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from ISO auctions, which are generally not considered to be liquid markets. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets. Alternative investments are categorized as Level 3 due to the absence of quoted market prices, illiquidity and the long-term nature of these assets. These investments are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager's and the Companies' measurement date.

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

The following table presents Dominion's quantitative information about Level 3 fair value measurements. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility, price correlations, load shaping, and usage factors.

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range		Weighted Average(1)
At December 31, 2012
Assets:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	13	Discounted Cash Flow	Market Price (per Dth)	(3)	(1) - 6		3
Electricity	6		Discounted Cash Flow	Market Price (per MWh)	(3)	30 - 85		50
FTRs	5		Discounted Cash Flow	Market Price (per MWh)	(3)	(6) - 7		1
Capacity	7		Discounted Cash Flow	Market Price (per MW)	(3)	95 - 115		101
Liquids(8)	21		Discounted Cash Flow	Market Price (per Gal)	(3)	0 - 3		1
Physical and Financial Options:
Natural Gas	5		Option Model	Market Price (per Dth)	(3)	3 - 5		4
				Price Volatility	(4)	21% - 36%		24	%
				Price Correlation	(5)	73% - 73%		73	%
Full Requirements Contracts:
Electricity	27		Discounted Cash Flow	Market Price (per MWh)	(3)	8 - 439		40
				Load Shaping	(6)	0% - 10%		5	%
				Usage Factor	(7)	2% - 16%		8	%
Total assets	$	84
Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	18	Discounted Cash Flow	Market Price (per Dth)	(3)	(1) - 18		3
Electricity	1		Discounted Cash Flow	Market Price (per MWh)	(3)	25 - 65		39
FTRs	3		Discounted Cash Flow	Market Price (per MWh)	(3)	(1) - 18		0
Liquids(8)	25		Discounted Cash Flow	Market Price (per Gal)	(3)	1 - 3		2
Physical and Financial Options:
Natural Gas(2)	12		Option Model	Market Price (per Dth)	(3)	3 - 8		5
				Price Volatility	(4)	21% - 36%		32	%
				Price Correlation	(5)	99	%	99	%
Total liabilities	$	59

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

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

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

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

(8) Includes NGLs.

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

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

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

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

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

Nonrecurring Fair Value Measurements

MERCHANT POWER STATIONS

In the third quarter of 2012, Dominion decided to pursue the sale of Brayton Point and Kincaid, as well as its 50% interest in Elwood, which is an equity method investment. Since Dominion is unlikely to operate the Brayton Point and Kincaid facilities through their estimated useful lives, Dominion evaluated these power stations for recoverability under a probability weighted approach and concluded that the carrying values of these facilities were not impaired as of September 30, 2012. 

At December 31, 2012, Dominion updated its recoverability analysis for Brayton Point and Kincaid to reflect bids received and an updated probability weighting. As a result of this updated evaluation, Dominion recorded an impairment charge of approximately $1.6 billion ($1.0 billion after-tax), which is included in other operations and maintenance expense in its Consolidated Statement of Income, to write down Brayton Point’s and Kincaid's long-lived assets to their estimated fair value of approximately $216 million. Dominion used a market approach to estimate the fair value of Brayton Point’s and Kincaid's long-lived assets. This was considered a Level 2 fair value measurement given it was based on bids received.

Any sale of Brayton Point, Kincaid, or Dominion's 50% interest in Elwood would be subject to the approval of Dominion's Board of Directors, as well as applicable regulatory approvals.

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

As a result of this evaluation in September 2012, Dominion recorded impairment and other charges of $435 million ($281 million after-tax) largely reflected in other operations and maintenance expense in its Consolidated Statement of Income. This primarily reflects a $378 million ($244 million after-tax) charge for the full impairment of Kewaunee's long-lived assets, a write down of materials and supplies inventories of $33 million ($21 million after-tax), and a $24 million ($16 million after-tax) charge related to severance costs.

The decision to decommission Kewaunee was approved by Dominion's Board of Directors in October 2012 after consideration of the factors discussed above, which made it uneconomic for Kewaunee to continue operations. The station is expected to cease power production in the second quarter of 2013 and commence decommissioning activities. Following station shutdown, Dominion plans to meet its obligations to the two utilities that purchase Kewaunee's generation through market purchases, until the power purchase agreements expire in December 2013.

In 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 ($107 million after-tax), which is now reflected in loss from discontinued operations in its Consolidated Statement of Income, to write down State Line's long-lived assets to their estimated fair value of $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), which is now reflected in loss from discontinued operations in its Consolidated Statement of Income, to write down State Line's long-lived assets to their estimated fair value of less than $1 million. State Line was retired in March 2012 and sold in the second quarter of 2012.

In December 2010, Dominion recorded an impairment charge of $31 million ($20 million after-tax), which is now reflected in loss from discontinued operations in its Consolidated Statement of Income, to write down the long-lived assets of Salem Harbor to their estimated fair value of less than $1 million as a result of profitability issues.

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 and Salem Harbor's long-lived assets in these 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.

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

EMISSIONS ALLOWANCES

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 22. 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 had 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.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion's pension and other postretirement benefit plans are presented in Note 21.

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 December 31, 2012
Assets:
Derivatives:
Commodity	$	12	$	639	$	84	$	735
Interest rate	—		93		—		93
Investments(1):
Equity securities:
U.S.:
Large Cap	1,973		—		—		1,973
Other	59		—		—		59
Non-U.S.:
Large Cap	12		—		—		12
Fixed Income:
Corporate debt instruments	—		325		—		325
U.S. Treasury securities and agency debentures	391		152		—		543
State and municipal	—		315		—		315
Other	—		7		—		7
Cash equivalents and other	13		67		—		80
Restricted cash equivalents	—		33		—		33
Total assets	$	2,460	$	1,631	$	84	$	4,175
Liabilities:
Derivatives:
Commodity	$	8	$	528	$	59	$	595
Interest rate	—		66		—		66
Total liabilities	$	8	$	594	$	59	$	661
At December 31, 2011
Assets:
Derivatives:
Commodity	$	44	$	828	$	93	$	965
Interest rate	—		105		—		105
Investments(1):
Equity securities:
U.S.:
Large Cap	1,718		—		—		1,718
Other	51		—		—		51
Non-U.S.:
Large Cap	10		—		—		10
Fixed Income:
Corporate debt instruments	—		332		—		332
U.S. Treasury securities and agency debentures	277		181		—		458
State and municipal	—		329		—		329
Other	—		23		—		23
Cash equivalents and other	—		60		—		60
Restricted cash equivalents	—		141		—		141
Total assets	$	2,100	$	1,999	$	93	$	4,192
Liabilities:
Derivatives:
Commodity	$	10	$	714	$	164	$	888
Interest rate	—		269		—		269
Total liabilities	$	10	$	983	$	164	$	1,157

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

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:

	2012			2011			2010
(millions)
Balance at January 1,	$	(71	)	$	(50	)	$	(66	)
Total realized and unrealized gains (losses):
Included in earnings	(15		)	(77		)	43
Included in other comprehensive income (loss)	101			14			(49		)
Included in regulatory assets/liabilities	30			(42		)	24
Settlements	47			88			(38		)
Transfers out of Level 3	(67		)	(4		)	36
Balance at December 31,	$	25		$	(71	)	$	(50	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$	42		$	22		$	(4	)

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

	Operating Revenue			Electric Fuel and Energy Purchases			Purchased Gas			Total
(millions)
Year Ended December 31, 2012
Total gains (losses) included in earnings	$	35		$	(50	)	$	—		$	(15	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	42			—			—			42
Year Ended December 31, 2011
Total gains (losses) included in earnings	$	(32	)	$	(45	)	$	—		$	(77	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	22			—			—			22
Year Ended December 31, 2010
Total gains (losses) included in earnings	$	(4	)	$	51		$	(4	)	$	43
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	(4		)	—			—			(4		)

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 December 31, 2012
Assets:
Derivatives:
Commodity	$	—	$	1	$	5	$	6
Investments(1):
Equity securities:
U.S.:
Large Cap	779		—		—		779
Other	27		—		—		27
Fixed Income:
Corporate debt instruments	—		196		—		196
U.S. Treasury securities and agency debentures	168		66		—		234
State and municipal	—		118		—		118
Other	—		1		—		1
Cash equivalents and other	7		31		—		38
Restricted cash equivalents	—		10		—		10
Total assets	$	981	$	423	$	5	$	1,409
Liabilities:
Derivatives:
Commodity	$	—	$	6	$	3	$	9
Interest rate	—		25		—		25
Total Liabilities	$	—	$	31	$	3	$	34
At December 31, 2011
Assets:
Derivatives:
Commodity	$	—	$	—	$	2	$	2
Investments(1):
Equity securities:
U.S.:
Large Cap	679		—		—		679
Other	23		—		—		23
Fixed Income:
Corporate debt instruments	—		214		—		214
U.S. Treasury securities and agency debentures	107		63		—		170
State and municipal	—		125		—		125
Other	—		16		—		16
Cash equivalents and other	—		40		—		40
Restricted cash equivalents	—		32		—		32
Total assets	$	809	$	490	$	2	$	1,301
Liabilities:
Derivatives:
Commodity	$	—	$	17	$	30	$	47
Interest rate	$	—	$	100	$	—	$	100
Total Liabilities	$	—	$	117	$	30	$	147

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

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:

	2012			2011			2010
(millions)
Balance at January 1,	$	(28	)	$	14		$	(10	)
Total realized and unrealized gains (losses):
Included in earnings	(50		)	(45		)	51
Included in regulatory assets/liabilities	30			(42		)	24
Settlements	50			45			(51		)
Transfers out of Level 3	—			—			—
Balance at December 31,	$	2		$	(28	)	$	14

The gains and losses included in earnings in the Level 3 fair value category, including those attributable to the change in unrealized gains and losses relating to assets still held at the reporting date, were classified in electric fuel and other energy-related purchases expense in Virginia Power's Consolidated Statements of Income for the years ended December 31, 2012, 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 years ended December 31, 2012, 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 fair values are as follows:

At December 31,	2012				2011
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	16,841	$	19,898	$	16,264	$	18,936
Long-term debt, including securities due within one year - VIE(3)	860		864		890		892
Junior subordinated notes	1,373		1,430		1,719		1,786
Subsidiary preferred stock(4)	257		255		257		256
Virginia Power
Long-term debt, including securities due within one year(2)	$	6,669	$	8,270	$	6,862	$	8,281
Preferred stock(4)	257		255		257		256

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2) Includes amounts which represent the unamortized discount and premium. At December 31, 2012, and 2011, includes the valuation of certain fair value hedges associated with Dominion's fixed rate debt, of approximately $93 million and $105 million, respectively.

(3) Includes amounts which represent the unamortized premium.

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

XML

Income Taxes (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Loss Carryforwards [Line Items]
Deferred tax liability, recapture of credits claimed in prior years that would result on completion of sale	$ 14
Reductions of deferred tax assets from the enactment of the Patient Protection and Affordable Care Act			57
Unrecognized tax benefits that would impact effective tax rate	167	184	133
Change in unrecognized tax benefits	1	51	(38)
Federal
Operating Loss Carryforwards [Line Items]
Operating loss carryforward	1,100
Tax credits	26
Accrual for interst on tax underpayments and overpayments	10
Federal | Scenario, Forecast
Operating Loss Carryforwards [Line Items]
Expiration of statutes of limitations	65
State
Operating Loss Carryforwards [Line Items]
Operating loss carryforward	1,400
Carryforwards valuation allowance	857
General Business | State
Operating Loss Carryforwards [Line Items]
Tax credits	96
Investment Credit That Expires In 2014 | State
Operating Loss Carryforwards [Line Items]
Tax credits	28
Tax credit carryforward valuation allowance	21
Fairless | State
Operating Loss Carryforwards [Line Items]
Reduction of valuation allowance	20
Brayton Point | State
Operating Loss Carryforwards [Line Items]
Reduction of valuation allowance	14
Virginia Electric and Power Company
Operating Loss Carryforwards [Line Items]
Reductions of deferred tax assets from the enactment of the Patient Protection and Affordable Care Act			17
Unrecognized tax benefits that would impact effective tax rate	13	20	14
Change in unrecognized tax benefits	(1)	(6)	(1)
Virginia Electric and Power Company | Federal
Operating Loss Carryforwards [Line Items]
Operating loss carryforward	220
Virginia Electric and Power Company | Federal | Scenario, Forecast
Operating Loss Carryforwards [Line Items]
Expiration of statutes of limitations	$ 35

XML

Employee Benefit Plans (AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit (credit) cost) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ 877		$ 610
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	2,865		2,211
Prior service (credit) cost	11		14
Total	2,876	[1]	2,225	[1]
Related expenses	2,900		2,200
Amount included in AOCI	1,800		1,400
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	230		100
Prior service (credit) cost	(71)		(86)
Total	159	[1]	14	[1]
Related expenses	158		14
Amount included in AOCI	69		(2)
Regulatory assets and liabilities			$ 16

[1] As of December 31, 2012, of the $2.9 billion and $158 million related to pension benefits and other postretirement benefits, $1.8 billion and$69 million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2011, of the $2.2 billion related to pension benefits, $1.4 billion is included in AOCI, with the remainder included in regulatory assets and liabilities; the $14 million related to other postretirement benefits consists of $16 million included in regulatory assets and liabilities and $(2) million included in AOCI.

XML

Investments (Fair Value of our Marketable Debt Securities by Contractual Maturity) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Schedule of Available-for-sale Securities [Line Items]
Due in one year or less	$ 116
Due after one year through five years	304
Due after five years through ten years	357
Due after ten years	369
Total	1,146
Virginia Electric and Power Company
Schedule of Available-for-sale Securities [Line Items]
Due in one year or less	18
Due after one year through five years	156
Due after five years through ten years	217
Due after ten years	157
Total	$ 548

XML

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)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Contingency [Line Items]
U.S. statutory rate	35.00%	35.00%	35.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	8.10%	1.80%	5.10%
Valuation allowances	(1.50%)	0.00%	(0.20%)
Production tax credits	(2.40%)	(0.60%)	(0.30%)
Amortization of investment tax credits	(0.30%)	(0.10%)	0.00%
AFUDC - equity	(4.10%)	(0.60%)	(0.40%)
Employee stock ownership plan deduction	(3.10%)	(0.70%)	(0.30%)
Goodwill	0.40%	0.00%	0.90%
Legislative change	0.00%	0.00%	1.10%
Other, net	(2.80%)	(0.60%)	(0.20%)
Effective tax rate	29.30%	34.20%	40.70%
Virginia Electric and Power Company
Income Tax Contingency [Line Items]
U.S. statutory rate	35.00%	35.00%	35.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.90%	4.40%	3.80%
Valuation allowances	0.00%	0.00%	0.00%
Production tax credits	0.00%	0.00%	0.00%
Amortization of investment tax credits	(0.10%)	(0.10%)	(0.10%)
AFUDC - equity	(0.90%)	(0.80%)	(1.10%)
Employee stock ownership plan deduction	0.00%	0.00%	0.00%
Goodwill	0.00%	0.00%	0.00%
Legislative change	0.00%	0.00%	1.10%
Other, net	0.40%	1.20%	0.20%
Effective tax rate	38.30%	39.70%	38.90%

XML

Long-Term Debt (Narrative) (Details) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	1 Months Ended			12 Months Ended			1 Months Ended								12 Months Ended				12 Months Ended
	Dec. 31, 2012	Nov. 30, 2012	Sep. 30, 2011	Dec. 31, 2012	Jul. 01, 2006 June 2006 hybrids	Jun. 30, 2006 June 2006 hybrids	Feb. 28, 2012 September 2006 hybrids	Dec. 31, 2012 September 2006 hybrids	Jun. 30, 2012 September 2006 hybrids	Mar. 31, 2012 September 2006 hybrids	Sep. 30, 2011 September 2006 hybrids	Sep. 30, 2006 September 2006 hybrids	Jun. 30, 2010 June 2009 hybrids	Jun. 30, 2009 June 2009 hybrids	Dec. 31, 2012 Unsecured Junior Subordinated Notes Payable to Affiliated Trusts	Dec. 31, 2011 Unsecured Junior Subordinated Notes Payable to Affiliated Trusts	Dec. 31, 2010 Unsecured Junior Subordinated Notes Payable to Affiliated Trusts	Dec. 31, 2012 7.83% Debentures due 12/1/2027	Dec. 31, 2012 Scenario, Forecast	Feb. 26, 2013 Subsequent Event	Jan. 31, 2013 Subsequent Event	Jan. 31, 2013 1.2% Senior Notes that Mature in 2018 Subsequent Event	Jan. 31, 2013 4% Senior Notes that mature in 2043 Subsequent Event	Jan. 31, 2013 Virginia Electric and Power Company 1.2% Senior Notes that Mature in 2018 Subsequent Event	Jan. 31, 2013 Virginia Electric and Power Company 4% Senior Notes that mature in 2043 Subsequent Event
Debt Instrument [Line Items]
Senior Notes																								$ 250	$ 500
Debt instrument, interest rate					2.825%	7.50%					2.30%	6.30%	8.375%					7.83%				1.20%	4.00%
Outstanding contingent convertible senior notes	82			82
Conversion rate (shares)	27.173			27.173																29.5147
Common stock principal amount of senior notes (per share)	$ 1,000			$ 1,000
Conversion price (per share)	$ 36.80			$ 36.80																$ 40.66
Conversion rate adjustment (shares)	$ 29.3863			$ 29.3863
Shares of stock issued if all converted																			900
Dividends declared payable (in dollars per share)	$ 56.25
Minimum consecutive trading days				20 days
Maximum consecutive trading days				30 days
Average trading price principal amount of the senior notes	120.00%			120.00%
Convertible senior notes converted by holders	61			61
Common stock, closing price equal (per share)	$ 40.84			$ 40.84
Redemption Rate				100.00%
Noncontrolling interest, ownership percentage by parent	100.00%			100.00%
Beneficial ownership percentage				97.00%
Beneficial ownership interest				3.00%
Percentage in capital trust assets				100.00%
Junior subordinated notes						300						500		685				258
Redemption of units of Dominion Resources Capital Trust I capital securties		250
Dominion Resources Capital Trust I capital securities		250
Rate of Dominion Resources Capital Trust I capital securties		7.83%
Redemption price per capital security																					$ 1,020
Interest charges															21	21	21
Underwriter option to purchase additional notes to cover over-allotments														60
Defferal period for interest rate payments				10 years
Period for consideration of proceeds (days)			180 days	365 days
Purchased and cancelled of junior subordinated notes								16	2	86
Tender offer to purchase additional hybrids							$ 150

XML

Operating Revenue (Operating Revenue) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended										12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012		Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011		Dec. 31, 2012	Dec. 31, 2011		Dec. 31, 2010
Electric sales:
Regulated											$ 7,102	$ 7,114		$ 7,123
Nonregulated											2,742	3,100		3,559
Gas sales:
Regulated											250	287		308
Nonregulated											1,071	1,635		2,010
Gas transportation and storage											1,401	1,506		1,493
Other											527	503		434
Total operating revenue	3,167	3,411	3,053	3,462	[1]	3,129	3,745	3,288	3,983	[1]	13,093	14,145	[2]	14,927	[2]
Virginia Electric and Power Company
Electric sales:
Regulated											7,102	7,114		7,123
Gas sales:
Other											124	132		96
Total operating revenue	$ 1,630	$ 2,086	$ 1,756	$ 1,754		$ 1,555	$ 2,177	$ 1,757	$ 1,757		$ 7,226	$ 7,246		$ 7,219

[1] Revenue and income amounts have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

[2] Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

XML

Goodwill and Intangible Assets (Goodwill) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 3,141	[1]	$ 3,141	[1]
Impairments/adjustments			0
Asset disposition adjustment	(11)
Goodwill, Ending Balance	3,130	[1]	3,141	[1]
Dominion Generation
Goodwill [Roll Forward]
Goodwill, Beginning Balance	1,338	[1]	1,338	[1]
Impairments/adjustments			0
Asset disposition adjustment	0
Goodwill, Ending Balance	1,338	[1]	1,338	[1]
Dominion Energy
Goodwill [Roll Forward]
Goodwill, Beginning Balance	712	[1]	712	[1]
Impairments/adjustments			0
Asset disposition adjustment	(11)
Goodwill, Ending Balance	701	[1]	712	[1]
DVP
Goodwill [Roll Forward]
Goodwill, Beginning Balance	1,091	[1]	1,091	[1]
Impairments/adjustments			0
Asset disposition adjustment	0
Goodwill, Ending Balance	1,091	[1]	1,091	[1]
Corporate and Other
Goodwill [Roll Forward]
Goodwill, Beginning Balance	0	[1]	0	[1]
Impairments/adjustments			0
Asset disposition adjustment	0
Goodwill, Ending Balance	$ 0	[1]	$ 0	[1]

[1] Goodwill amounts do not contain any accumulated impairment losses.

XML

Commitments and Contingencies (Nuclear Insurance) (Details) (USD $)	Dec. 31, 2012
Millstone
Guarantor Obligations [Line Items]
Property insurance coverage	$ 2,750,000
Kewaunee
Guarantor Obligations [Line Items]
Property insurance coverage	1,800,000
Surry | Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Property insurance coverage	2,550,000	[1]
North Anna | Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Property insurance coverage	2,550,000	[1]
Surry and North Anna
Guarantor Obligations [Line Items]
Coverage amount	$ 1,000,000,000

[1] Surry and North Anna share a blanket property limit of $1 billion.

XML

Related Party Transactions

12 Months Ended

Dec. 31, 2012

Related Party Transactions [Abstract]

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 risks associated with purchases of natural gas.

As of December 31, 2012 and 2011, Virginia Power's derivative liabilities with affiliates were not material.

DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage. Presented below are significant transactions with DRS and other affiliates:

Year Ended December 31,	2012		2011		2010
(millions)
Commodity purchases from affiliates	$	368	$	376	$	373
Services provided by affiliates	399		393		469
Services provided to affiliates	19		21		19

In the fourth quarter of 2011, a subsidiary of Virginia Power purchased nuclear fuel-related inventory from an affiliate for $39 million for future use at its nuclear generation stations.

Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were $243 million in short-term demand note borrowings from Dominion as of December 31, 2012. There were no short-term demand note borrowings from Dominion as of December 31, 2011. Virginia Power's outstanding borrowings, net of repayments, under the Dominion money pool for its nonregulated subsidiaries totaled $192 million and $187 million as of December 31, 2012 and 2011, respectively. Interest charges related to Virginia Power's borrowings from Dominion were immaterial for the years ended December 31, 2012, 2011 and 2010.

In 2010 Virginia Power issued 33,013 shares of its common stock to Dominion for approximately $1 billion, for the purpose of retiring short-term demand note borrowings from Dominion. There were no such issuances of common stock in 2011 and 2012.

XML

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Long-term Debt, Unclassified [Abstract]

Long term Debt

At December 31,	2012 Weighted- average Coupon(1)		2012			2011
(millions, except percentages)
Virginia Electric and Power Company:
Unsecured Senior Notes:
4.75% to 8.625%, due 2012 to 2017	5.50	%	$	1,706		$	2,321
2.95% to 8.875%, due 2018 to 2038	5.83	%	4,008			3,558
Tax-Exempt Financings(2):
Variable rates, due 2016 to 2041	1.14	%	454			454
1.5% to 6.5%, due 2017 to 2040	3.65	%	508			533
Virginia Electric and Power Company total principal			$	6,676		$	6,866
Securities due within one year	4.88	%	(418		)	(616		)
Unamortized discount and premium, net			(7		)	(4		)
Virginia Electric and Power Company total long-term debt			$	6,251		$	6,246
Dominion Resources, Inc.:
Unsecured Senior Notes:
Variable rate, due 2013	0.41	%	$	400		$	—
1.4% to 7.195%, due 2012 to 2017	3.72	%	3,041			3,545
2.75% to 8.875%, due 2018 to 2042(3)	5.71	%	5,099			4,399
Unsecured Convertible Senior Notes, 2.125%, due 2023(4)			82			143
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031	7.85	%	268			268
Enhanced Junior Subordinated Notes:
7.5% and 8.375%, due 2064 and 2066	8.11	%	985			985
Variable rate, due 2066(5)	2.77	%	380			468
Unsecured Debentures and Senior Notes(6):
5.0% and 6.625%, due 2013 and 2014	5.06	%	622			622
6.8% and 6.875%, due 2026 and 2027	6.81	%	89			89
Dominion Energy, Inc.:
Secured Senior Notes:
5.03% to 5.78%, due 2013(7)	5.07	%	842			842
7.33%, due 2020(8)			145			159
Tax-Exempt Financings(9):
2.25% to 5.75%, due 2033 to 2042	3.34	%	284			284
Variable rate, due 2041	1.16	%	75			75
Virginia Electric and Power Company total principal (from above)			6,676			6,866
Dominion Resources, Inc. total principal			$	18,988		$	18,745
Fair value hedge valuation(10)			93			105
Securities due within one year(11)	4.53	%	(2,223		)	(1,479		)
Unamortized discount and premium, net			(7		)	23
Dominion Resources, Inc. total long-term debt			$	16,851		$	17,394

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2012.

(2) These financings relate to certain pollution control equipment at Virginia Power's generating facilities. Certain variable rate tax-exempt financings are supported by a $120 million credit facility that terminates in September 2017.

(3) At the option of holders, $510 million of Dominion's 5.25% senior notes due 2033 and $600 million of Dominion's 8.875% senior notes due 2019 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015 and January 2014, respectively.

(4) Convertible into a combination of cash and shares of Dominion's common stock at any time when the closing price of common stock equals 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter. At the option of holders on December 15, 2013 or 2018, these securities are subject to redemption at 100% of the principal amount plus accrued interest. These senior notes have been callable by Dominion since December 15, 2011.

(5) In September 2011, the $500 million6.3% September 2006 hybrids began bearing interest at the three-month LIBOR plus 2.3%, reset quarterly.

(6) Represents debt assumed by Dominion from the merger of its former CNG subsidiary.

(7) Juniper notes issued in 2004 and consolidated in October 2011 due to Dominion becoming the primary beneficiary of this VIE. This amount excludes $18 million and $48 million of unamortized premium in 2012 and 2011, respectively. The debt is non-recourse to Dominion and is secured by Juniper's assets.

(8) Represents debt associated with Kincaid. The debt is non-recourse to Dominion and is secured by the facility's assets ($552 million at December 31, 2012) and revenue. Dominion announced in the third quarter of 2012 that it was pursuing the sale of Kincaid. Dominion anticipates redeeming the notes as a condition to a sale of Kincaid.

(9) Includes debt issued by the Massachusetts Development Finance Agency on behalf of Brayton Point. Dominion announced in the third quarter of 2012 that it was pursuing the sale of Brayton Point.

(10) Represents the valuation of certain fair value hedges associated with Dominion's fixed rate debt.

(11) Includes $23 million of net unamortized premium and fair value hedge valuation in 2012 and $4 million of net unamortized discount in 2011.

Scheduled principal payments of long-term debt

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2012, were as follows:

	2013			2014			2015			2016			2017			Thereafter			Total
(millions, except percentages)
Virginia Power	$	418		$	17		$	211		$	476		$	679		$	4,875		$	6,676
Weighted-average Coupon	4.88		%	7.73		%	5.39		%	5.27		%	5.44		%	5.26		%
Dominion
Secured Senior Notes	$	852		$	15		$	18		$	20		$	22		$	60		$	987
Unsecured Senior Notes	1,090			1,065			960			1,351			1,303			9,278			15,047
Tax-Exempt Financings	—			—			—			19			75			1,227			1,321
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts	258			—			—			—			—			10			268
Enhanced Junior Subordinated Notes	—			—			—			—			—			1,365			1,365
Total	$	2,200		$	1,080		$	978		$	1,390		$	1,400		$	11,940		$	18,988
Weighted-average Coupon	4.53		%	3.99		%	4.50		%	4.27		%	4.60		%	5.54		%

Trust preferred securities and junior subordinated notes outstanding text block

The following table provides summary information about the capital securities and junior subordinated notes outstanding as of December 31, 2012:

Date Established	Capital Trusts	Units	Rate		Capital Securities Amount		Common Securities Amount
		(thousands)			(millions)
December 1997	Dominion Resources Capital Trust I(1)	250	7.83	%	$	250	$	7.7
January 2001	Dominion Resources Capital Trust III(2)	10	8.4		10		0.3

Junior subordinated notes/debentures held as assets by each capital trust were as follows:

(1) $258 million-Dominion Resources, Inc. 7.83% Debentures due 12/1/2027.

(2) $10 million-Dominion Resources, Inc. 8.4% Debentures due 1/15/2031.

XML

Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2012

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets

GOODWILLAND INTANGIBLE ASSETS

Goodwill

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

	Dominion Generation		Dominion Energy			DVP		Corporate and Other		Total
(millions)
Balance at December 31, 2010(1)	$	1,338	$	712		$	1,091	$	—	$	3,141
Impairments/adjustments	—		—			—		—		—
Balance at December 31, 2011(1)	$	1,338	$	712		$	1,091	$	—	$	3,141
Asset disposition adjustment	—		(11		)	—		—		(11		)
Balance at December 31, 2012(1)	$	1,338	$	701		$	1,091	$	—	$	3,130

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

Other Intangible Assets

Dominion's and Virginia Power's other intangible assets are subject to amortization over their estimated useful lives. Dominion's amortization expense for intangible assets was $82 million, $78 million and $107 million for 2012, 2011 and 2010, respectively. In 2012, Dominion acquired $102 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 19 years. Amortization expense for Virginia Power's intangible assets was $22 million, $22 million and $26 million for 2012, 2011, and 2010, respectively. In 2012, Virginia Power acquired $53 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 31 years. The components of intangible assets are as follows:

At December 31,	2012				2011
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion
Software, licenses and other	$	859	$	327	$	888	$	278
Emissions allowances	5		1		80		53
Total	$	864	$	328	$	968	$	331
Virginia Power
Software, licenses and other	$	303	$	122	$	285	$	102
Total	$	303	$	122	$	285	$	102

Annual amortization expense for these intangible assets is estimated to be as follows:

	2013		2014		2015		2016		2017
(millions)
Dominion	$	65	$	56	$	43	$	37	$	25
Virginia Power	$	20	$	18	$	12	$	8	$	5

XML

Employee Benefit Plans (Accumulated Benefit Obligation in Excess of Plan Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Accumulated benefit obligation	$ 4,850	[1]	$ 95
Fair value of plan assets	$ 4,189	[1]	$ 0

[1] The increase from 2011 is primarily due to a decrease in the discount rate.

XML

Short-Term Debt And Credit Agreements

12 Months Ended

Dec. 31, 2012

Short-term Debt, Other Disclosures [Abstract]

Short-Term Debt And Credit Agreements

SHORT-TERM DEBTAND CREDIT AGREEMENTS

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.

DOMINION

Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities, were as follows:

At December 31,	Facility Limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Capacity Available
(millions)
2012
Joint revolving credit facility(1)	$	3,000	$	2,412		$	—	$	588
Joint revolving credit facility(2)	500		—			26		474
Total	$	3,500	$	2,412	(3)	$	26	$	1,062
2011
Joint revolving credit facility(1)	$	3,000	$	1,814		$	—	$	1,186
Joint revolving credit facility(2)	500		—			36		464
Total	$	3,500	$	1,814	(3)	$	36	$	1,650

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

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

(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion's credit facilities were 0.49% and 0.47% at December 31, 2012 and 2011, respectively.

VIRGINIA POWER

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.

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:

At December 31,	Facility Sub-limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Sub-Limit Capacity Available
(millions)
2012
Joint revolving credit facility(1)	$	1,000	$	992		$	—	$	8
Joint revolving credit facility(2)	250		—			2		248
Total	$	1,250	$	992	(3)	$	2	$	256
2011
Joint revolving credit facility(1)	$	1,000	$	894		$	—	$	106
Joint revolving credit facility(2)	250		—			15		235
Total	$	1,250	$	894	(3)	$	15	$	341

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

(2) Effective September 2012, the maturity date for $400 million of the $500 million in committed capacity of this credit facility was extended from September 2016 to September 2017. The remaining $100 million continues to have a maturity date of September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power's current sub-limit under this credit facility can be increased or decreased multiple times per year.

(3) The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.47% and 0.46% at December 31, 2012 and 2011, respectively.

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

XML

Regulatory Assets and Liabilities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Regulatory Assets And Liabilities [Line Items]
Regulatory assets represented past expenditures not earning return	$ 319
Period expenditures expected to be recovered (years)	2 years
Virginia Electric and Power Company
Regulatory Assets And Liabilities [Line Items]
Regulatory assets represented past expenditures not earning return	$ 240

XML

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation [Abstract]

Changes to Asset Retirement Obligations

The changes to AROs during 2011 and 2012 were as follows:

	Amount
(millions)
Dominion
AROs at December 31, 2010(1)	$	1,591
Obligations incurred during the period	16
Obligations settled during the period	(16		)
Revisions in estimated cash flows(2)	(277		)
Accretion	84
AROs at December 31, 2011(1)	$	1,398
Obligations incurred during the period	24
Obligations settled during the period	(13		)
Revisions in estimated cash flows(3)	242
Accretion	77
Other	(23		)
AROs at December 31, 2012(1)	$	1,705
Virginia Power
AROs at December 31, 2010(4)	$	672
Obligations incurred during the period	10
Obligations settled during the period	(3		)
Revisions in estimated cash flows(2)	(90		)
Accretion	36
AROs at December 31, 2011(4)	$	625
Obligations incurred during the period	18
Obligations settled during the period	(1		)
Revisions in estimated cash flows(5)	41
Accretion	34
Other	(12		)
AROs at December 31, 2012	$	705

(1) Includes $14 million, $15 million and $64 million reported in other current liabilities at December 31, 2010, 2011, and 2012, respectively.

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

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

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

(5) Primarily reflects the effect of higher anticipated nuclear decommissioning costs.

XML

Long-Term Debt (Trust Preferred Securities and Junior Subordinated Notes Outstanding) (Details) (USD $) In Millions, unless otherwise specified					12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2012 December 1997 Dominion Resources Capital Trust I		Dec. 31, 2012 January 2001 Dominion Resources Capital Trust III		Dec. 31, 2012 7.83% Debentures due 12/1/2027	Dec. 31, 2012 8.4% Debentures due 1/15/2031
Debt Instrument [Line Items]
Date Established					December 1997		January 2001
Units					0	[1]	0	[2]
Rate					7.83%	[1]	8.40%	[2]
Capital Securities Amount					$ 250	[1]	$ 10	[2]
Common Securities Amount	5,493.0	[3]	5,180.0	[3]	7.7	[1]	0.3	[2]
Junior subordinated notes									$ 258	$ 10
Debt instrument, interest rate									7.83%	8.40%
Debt instrument maturity date									Dec. 01, 2027	Jan. 15, 2031

[1] $258 million-Dominion Resources, Inc. 7.83% Debentures due 12/1/2027.

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

[3] 1 billion shares authorized; 576 million shares and 570 million shares outstanding at December 31, 2012 and 2011, respectively.

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Expense (Benefit) [Abstract]

Income tax expense for continuing operations including noncontrolling interests

Details of income tax expense for continuing operations including noncontrolling interests were as follows:

	Dominion(1)									Virginia Power(2)
Year Ended December 31,	2012			2011			2010			2012			2011			2010
(millions)
Current:
Federal	$	(117	)	$	3		$	894		$	70		$	(35	)	$	(78	)
State	80			9			309			81			79			10
Total current expense (benefit)	(37		)	12			1,203			151			44			(68		)
Deferred:
Federal	214			694			818			482			484			537
State	(30		)	50			93			21			13			74
Total deferred expense	184			744			911			503			497			611
Amortization of deferred investment tax credits	(1		)	(2		)	(2		)	(1		)	(1		)	(1		)
Total income tax expense	$	146		$	754		$	2,112		$	653		$	540		$	542

(1) In 2012, Dominion's current federal income tax benefit includes a benefit related to the carryback of its current year operating loss, and deferred state income tax benefit reflects the impact of Brayton Point, Kincaid and Kewaunee impairment charges. In 2011, Dominion's federal income tax expense includes a benefit related to its current year operating loss that is expected to be used in future years, and state income tax expense reflects changes in the amount of income apportioned among states, higher tax credits, claims for refunds and previously unrecognized tax benefits due to the expiration of statutes of limitations.

(2) In 2011, Virginia Power's federal income tax expense includes a benefit related to a portion of its current year operating loss that is expected to be used in future years. Also, in 2011 and 2010, Virginia Power's federal income tax expense reflects the amounts of current year operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

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
Year Ended December 31,	2012		2011		2010		2012		2011		2010
U.S. statutory rate	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit	8.1		1.8		5.1		3.9		4.4		3.8
Valuation allowances	(1.5	)	—		(0.2	)	—		—		—
Production tax credits	(2.4	)	(0.6	)	(0.3	)	—		—		—
Amortization of investment tax credits	(0.3	)	(0.1	)	—		(0.1	)	(0.1	)	(0.1	)
AFUDC - equity	(4.1	)	(0.6	)	(0.4	)	(0.9	)	(0.8	)	(1.1	)
Employee stock ownership plan deduction	(3.1	)	(0.7	)	(0.3	)	—		—		—
Goodwill	0.4		—		0.9		—		—		—
Legislative change	—		—		1.1		—		—		1.1
Other, net	(2.8	)	(0.6	)	(0.2	)	0.4		1.2		0.2
Effective tax rate	29.3	%	34.2	%	40.7	%	38.3	%	39.7	%	38.9	%

The Companies deferred income taxes components

The Companies' deferred income taxes consist of the following:

	Dominion						Virginia Power
At December 31,	2012			2011			2012			2011
(millions)
Deferred income taxes:
Total deferred income tax assets	$	2,505		$	2,229		$	466		$	503
Total deferred income tax liabilities	7,716			7,424			4,238			3,759
Total net deferred income tax liabilities	$	5,211		$	5,195		$	3,772		$	3,256
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	4,601		$	4,008		$	3,394		$	2,758
Nuclear decommissioning	994			913			407			374
Deferred state income taxes	474			493			265			243
Federal benefit of deferred state income taxes	(166		)	(173		)	(93		)	(85		)
Deferred fuel, purchased energy and gas costs	3			161			(16		)	144
Pension benefits	231			396			(17		)	8
Other postretirement benefits	(171		)	(167		)	(7		)	(13		)
Loss and credit carryforwards	(656		)	(577		)	(77		)	(55		)
Reserve for rate proceedings	—			(54		)	—			(54		)
Partnership basis differences	174			274			—			—
Valuation allowances	93			96			—			—
Other	(366		)	(175		)	(84		)	(64		)
Total net deferred income tax liabilities	$	5,211		$	5,195		$	3,772		$	3,256

Reconciliation of changes in the Companies unrecognized tax benefits

A reconciliation of changes in the Companies' unrecognized tax benefits follows:

	Dominion									Virginia Power
	2012			2011			2010			2012			2011			2010
(millions)
Balance at January 1	$	347		$	307		$	291		$	114		$	117		$	121
Increases-prior period positions	28			127			34			4			22			4
Decreases-prior period positions	(106		)	(119		)	(75		)	(80		)	(51		)	(33		)
Increases-current period positions	43			64			61			24			47			25
Decreases-current period positions	—			(21		)	—			—			(21		)	—
Settlements with tax authorities	(4		)	—			—			(4		)	—			—
Expiration of statutes of limitation	(15		)	(11		)	(4		)	(1		)	—			—
Balance at December 31	$	293		$	347		$	307		$	57		$	114		$	117

Earliest tax year remaining

For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows:

State	Earliest Open Tax Year
Pennsylvania	2009
Connecticut	2009
Massachusetts	2008
Virginia(1)	2009
West Virginia	2009

(1) Virginia is the only state considered major for Virginia Power's operations.

XML

Preferred Stock Preferred Stock (Schedule of Preferred Stock) (Details) (Virginia Electric and Power Company, USD $) In Thousands, except Per Share data, unless otherwise specified	0 Months Ended	12 Months Ended
	Mar. 20, 2011	Dec. 31, 2012
Class of Stock [Line Items]
Issued and Outstanding Shares		2,590
Entitled Per Share Upon Liquidation		$ 100.00
Dvidend rate	6.25%	6.12%
$5.00
Class of Stock [Line Items]
Dividend		$ 5.00
Issued and Outstanding Shares		107
Entitled Per Share Upon Liquidation		$ 112.50
$4.04
Class of Stock [Line Items]
Dividend		$ 4.04
Issued and Outstanding Shares		13
Entitled Per Share Upon Liquidation		$ 102.27
$4.20
Class of Stock [Line Items]
Dividend		$ 4.20
Issued and Outstanding Shares		15
Entitled Per Share Upon Liquidation		$ 102.50
$4.12
Class of Stock [Line Items]
Dividend		$ 4.12
Issued and Outstanding Shares		32
Entitled Per Share Upon Liquidation		$ 103.73
$4.80
Class of Stock [Line Items]
Dividend		$ 4.80
Issued and Outstanding Shares		73
Entitled Per Share Upon Liquidation		$ 101.00
$7.05
Class of Stock [Line Items]
Dividend		$ 7.05
Issued and Outstanding Shares		500
Entitled Per Share Upon Liquidation		$ 100.36	[1]
$6.98
Class of Stock [Line Items]
Dividend		$ 6.98
Issued and Outstanding Shares		600
Entitled Per Share Upon Liquidation		$ 100.35	[2]
Flex Money Market Preferred 12/02, Series A
Class of Stock [Line Items]
Issued and Outstanding Shares		1,250
Entitled Per Share Upon Liquidation		$ 100.00	[3]

[1] Through 7/31/2013; $100.00 commencing 8/1/2013

[2] Through 8/31/2013; $100.00 commencing 9/1/2013.

[3] Dividend rate was 6.25% until 3/20/2011. Effective 3/20/11 the rate reset to 6.12% until 3/20/2014 after which the rate will be determined according to periodic auctions for periods established by Virginia Power at the time of the auction process.

XML

Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net deferred gains (losses) on derivatives-hedging activities, tax	$ 5	$ 48	$ (52)
Changes in unrealized net gains (losses) on investment securities, tax	(68)	(7)	(54)
Changes in net unrecognized pension and other postretirement benefit costs, tax	209	147	40
Net derivative (gains) losses-hedging activities, tax	34	28	193
Net realized (gains) losses on investment securities, tax	16	(4)	9
Net pension and other postretirement benefit costs, tax	(32)	(25)	(38)
Virginia Electric and Power Company
Net deferred gains (losses) on derivatives-hedging activities, tax	3	3	1
Changes in unrealized net gains (losses) on investment securities, tax	(7)	(1)	(6)
Net derivative (gains) losses-hedging activities, tax	(2)	0	4
Net realized (gains) losses on investment securities, tax	$ 2	$ 0	$ 2

XML

Investments (Investments Under Equity Method of Accounting) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 558		$ 553
Commitment to invest in clean power and technology	50
Fowler I Holdings LLC
Schedule of Equity Method Investments [Line Items]
Ownership%	50.00%
Investment Balance	158		166
Description	Wind-powered merchant generation facility
NedPower Mount Storm LLC
Schedule of Equity Method Investments [Line Items]
Ownership%	50.00%
Investment Balance	137		146
Description	Wind-powered merchant generation facility
Elwood Energy LLC
Schedule of Equity Method Investments [Line Items]
Ownership%	50.00%
Investment Balance	117		108
Description	Natural gas-fired merchant generation peaking facility
Iroquois Gas Transmission System, LP
Schedule of Equity Method Investments [Line Items]
Ownership%	24.72%
Investment Balance	102		104
Description	Gas transmission system
Blue Racer Midstream LLC
Schedule of Equity Method Investments [Line Items]
Ownership%	50.00%
Investment Balance	39		0
Description	Midstream gas and related services
Other
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 5	[1]	$ 29	[1]

[1] Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018.

XML

Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2012 Appalachian E & P	Dec. 31, 2011 Appalachian E & P	Dec. 31, 2010 Appalachian E & P	Dec. 31, 2012 Peoples	Dec. 31, 2011 Peoples	Dec. 31, 2010 Peoples	Dec. 31, 2012 Virginia Electric and Power Company	Dec. 31, 2011 Virginia Electric and Power Company	Dec. 31, 2010 Virginia Electric and Power Company
Operating Activities
Net income including noncontrolling interests	$ 329	$ 1,426	[1]	$ 2,825	[1]
Net income attributable to Dominion	302	1,408	[1]	2,808	[1]							1,050	822	852
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Gain from sale of Appalachian E&P operations	0	0	[1]	(2,467)	[1]
Loss from sale of Peoples	0	0		113
Charges (payments) related to workforce reduction program	(9)	(115)		229								(4)	(53)	98
Impairment of generation assets (including discontinued operations)	2,089	283		194								0	228	0
Net reserves (payments) related to rate refunds	(151)	3		(500)								(151)	3	(500)
Contributions to pension plans	0	0		(650)								0	0	(302)
Depreciation, depletion and amortization (including nuclear fuel)	1,443	1,288		1,258								927	838	782
Deferred income taxes and investment tax credits	246	756		682								502	496	609
Gain on the sale of assets to Blue Racer	(81)	0		0
Other adjustments	(155)	(92)		(40)								(66)	(40)	(40)
Changes in:
Accounts receivable	292	365		(60)								126	76	(9)
Affiliated accounts receivable and payable												(2)	(7)	11
Inventories	33	(185)		35								8	(200)	17
Prepayments	(85)	(19)		139								18	24	(10)
Deferred fuel and purchased gas costs, net	368	(3)		(246)								378	12	(213)
Accounts payable	(61)	(413)		119								19	(117)	108
Accrued interest, payroll and taxes	(12)	(216)		166								(22)	12	1
Other operating assets and liabilities	(109)	(95)		28								(77)	(70)	5
Net cash provided by operating activities	4,137	2,983		1,825								2,706	2,024	1,409
Investing Activities
Plant construction and other property additions (including nuclear fuel)	(4,145)	(3,652)		(3,422)								(2,082)	(1,885)	(2,113)
Purchases of nuclear fuel												(206)	(205)	(121)
Purchases of securities												(638)	(1,057)	(1,211)
Proceeds from sales of securities												626	1,030	1,192
Proceeds from the sale of business						0	0	3,450	0	0	741
Proceeds from sales of securities	1,356	1,757		2,814
Purchases of securities	(1,392)	(1,824)		(2,851)
Proceeds from Blue Racer	58	55
Restricted cash equivalents	108	259		(396)								22	137	(165)
Other	118	139		83								(4)	33	(7)
Net cash provided by (used in) investing activities	(3,840)	(3,321)		419								(2,282)	(1,947)	(2,425)
Financing Activities
Issuance of short-term debt, net	598	429		91								98	294	158
Proceeds from Short-term Debt	400	0		0
Issuance of affiliated current borrowings, net												248	85	1,101
Issuance and remarketing of long-term debt	1,500	2,320		1,090								450	235	605
Repayment and repurchase of long-term debt	(1,675)	(637)		(1,492)
Repayment and repurchase of long-term debt												(641)	(91)	(347)
Issuance of common stock	265	38		74										1,000
Repurchase of common stock	0	(601)		(900)
Common dividend payments	(1,209)	(1,129)		(1,076)								(559)	(557)	(500)
Subsidiary preferred dividend payments	(16)	(17)		(17)								(16)	(17)	(17)
Other	(14)	(25)		(2)								(5)	(2)	2
Net cash provided by (used in) financing activities	(151)	378		(2,232)								(425)	(53)	1,002
Increase in cash and cash equivalents	146	40		12								(1)	24	(14)
Cash and cash equivalents at beginning of year	102	62		50								29	5	19
Cash and cash equivalents at end of year	248	102		62								28	29	5
Supplemental Cash Flow Information
Interest and related charges, excluding capitalized amounts	913	920		894								376	376	349
Income taxes	(58)	166		991								225	(27)	(101)
Significant noncash investing and financing activities:
Accrued capital expenditures	388	328		240								242	199	136
Consolidation of VIE - assets at fair value	0	957		0
Consolidation of VIE - debt	0	896		0
Settlement of debt and issuance of common stock to Dominion												$ 0	$ 0	$ 1,000

[1] Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

XML

Quarterly Financial and Common Stock Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial and Common Stock Data

	First Quarter(2)			Second Quarter			Third Quarter			Fourth Quarter			Full Year
(millions, except per share amounts)
2012
Operating revenue	$	3,462		$	3,053		$	3,411		$	3,167		$	13,093
Income (loss) from operations	913			617			518			(892		)	1,156
Net income (loss) including noncontrolling interests	501			265			215			(652		)	329
Income (loss) from continuing operations(1)	493			276			214			(659		)	324
Income (loss) from discontinued operations(1)	1			(18		)	(5		)	—			(22		)
Net income (loss) attributable to Dominion	494			258			209			(659		)	302
Basic EPS:
Income (loss) from continuing operations(1)	0.86			0.48			0.37			(1.15		)	0.57
Income (loss) from discontinued operations(1)	—			(0.03		)	(0.01		)	—			(0.04		)
Net income (loss) attributable to Dominion	0.86			0.45			0.36			(1.15		)	0.53
Diluted EPS:
Income (loss) from continuing operations(1)	0.86			0.48			0.37			(1.15		)	0.57
Loss from discontinued operations(1)	—			(0.03		)	(0.01		)	—			(0.04		)
Net income (loss) attributable to Dominion	0.86			0.45			0.36			(1.15		)	0.53
Dividends declared per share	0.5275			0.5275			0.5275			0.5275			2.11
Common stock prices (intraday high-low)	$53.68  - 48.87			$54.69  - 49.87			$55.62 - 52.15			$53.89  - 48.94			$55.62  - 48.87
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Full Year
2011(2)
Operating revenue	$	3,983		$	3,288		$	3,745		$	3,129		$	14,145
Income from operations	993			733			828			340			2,894
Net income including noncontrolling interests	483			340			396			207			1,426
Income from continuing operations(1)	504			341			388			200			1,433
Income (loss) from discontinued operations(1)	(25		)	(5		)	4			1			(25		)
Net income attributable to Dominion	479			336			392			201			1,408
Basic EPS:
Income from continuing operations(1)	0.87			0.59			0.68			0.35			2.50
Income (loss) from discontinued operations(1)	(0.04		)	(0.01		)	0.01			—			(0.04		)
Net income attributable to Dominion	0.83			0.58			0.69			0.35			2.46
Diluted EPS:
Income from continuing operations(1)	0.86			0.59			0.68			0.35			2.49
Income (loss) from discontinued operations(1)	(0.04		)	(0.01		)	0.01			—			(0.04		)
Net income attributable to Dominion	0.82			0.58			0.69			0.35			2.45
Dividends declared per share	0.4925			0.4925			0.4925			0.4925			1.97
Common stock prices (intraday high-low)	$46.56  - 42.06			$48.55  - 43.27			$51.44 - 44.50			$53.59  - 48.21			$53.59  - 42.06

(1) Amounts attributable to Dominion's common shareholders.

(2) Revenue and income amounts have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

Virginia Electric and Power Company

Quarterly Financial and Common Stock Data

Virginia Power's quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
(millions)
2012
Operating revenue	$	1,754	$	1,756	$	2,086	$	1,630	$	7,226
Income from operations	468		361		746		417		1,992
Net income	243		172		415		220		1,050
Balance available for common stock	239		168		411		216		1,034
2011
Operating revenue	$	1,757	$	1,757	$	2,177	$	1,555	$	7,246
Income from operations	511		471		568		55		1,605
Net income	278		241		297		6		822
Balance available for common stock	274		237		293		1		805

XML

Earnings Per Share (Calculation of our Basic and Diluted EPS) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended										12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012		Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Earnings Per Share [Abstract]
Net income attributable to Dominion	$ (659)	$ 209	$ 258	$ 494	[1]	$ 201	$ 392	$ 336	$ 479	[1]	$ 302		$ 1,408	[2]	$ 2,808	[2]
Average shares of common stock outstanding-Basic											572.9		573.1		588.9
Net effect of potentially dilutive securities											1.0	[3]	1.5	[3]	1.2	[3]
Average shares of common stock outstanding-Diluted											573.9		574.6		590.1
Earnings Per Common Share-Basic (in dollars per share)	$ (1.15)	$ 0.36	$ 0.45	$ 0.86	[1]	$ 0.35	$ 0.69	$ 0.58	$ 0.83	[1]	$ 0.53		$ 2.46	[2]	$ 4.77	[2]
Earnings Per Common Share-Diluted (in dollars per share)	$ (1.15)	$ 0.36	$ 0.45	$ 0.86	[1]	$ 0.35	$ 0.69	$ 0.58	$ 0.82	[1]	$ 0.53		$ 2.45	[2]	$ 4.76	[2]

[1] Revenue and income amounts have been recast to reflect Salem Harbor and State Line as discontinued operations, as discussed in Note 3.

[2] Recast to reflect Salem Harbor and State Line as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast.

[3] Potentially dilutive securities consist of options, goal-based stock and contingently convertible senior notes.

XML

Preferred Stock (Narrative) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Class of Stock [Line Items]
Preferred stock shares authorized	20,000,000
Preferred stock shares issued	0	0
Virginia Electric and Power Company
Class of Stock [Line Items]
Preferred stock shares authorized	10,000,000
Preferred stock shares issued	2,590,000	2,590,000
Preferred stock shares outstanding	2,590,000	2,590,000
Entitled Per Share Upon Liquidation	100

XML

Income Taxes (Earliest Tax Year) (Details)	12 Months Ended
	Dec. 31, 2012
Pennsylvania
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2009
Connecticut
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2009
Massachusetts
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2008
Virginia
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2009	[1]
West Virginia
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2009

[1] Virginia is the only state considered major for Virginia Power's operations.

XML

Long-Term Debt

12 Months Ended

Dec. 31, 2012

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

LONG-TERM DEBT

At December 31,	2012 Weighted- average Coupon(1)		2012			2011
(millions, except percentages)
Virginia Electric and Power Company:
Unsecured Senior Notes:
4.75% to 8.625%, due 2012 to 2017	5.50	%	$	1,706		$	2,321
2.95% to 8.875%, due 2018 to 2038	5.83	%	4,008			3,558
Tax-Exempt Financings(2):
Variable rates, due 2016 to 2041	1.14	%	454			454
1.5% to 6.5%, due 2017 to 2040	3.65	%	508			533
Virginia Electric and Power Company total principal			$	6,676		$	6,866
Securities due within one year	4.88	%	(418		)	(616		)
Unamortized discount and premium, net			(7		)	(4		)
Virginia Electric and Power Company total long-term debt			$	6,251		$	6,246
Dominion Resources, Inc.:
Unsecured Senior Notes:
Variable rate, due 2013	0.41	%	$	400		$	—
1.4% to 7.195%, due 2012 to 2017	3.72	%	3,041			3,545
2.75% to 8.875%, due 2018 to 2042(3)	5.71	%	5,099			4,399
Unsecured Convertible Senior Notes, 2.125%, due 2023(4)			82			143
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031	7.85	%	268			268
Enhanced Junior Subordinated Notes:
7.5% and 8.375%, due 2064 and 2066	8.11	%	985			985
Variable rate, due 2066(5)	2.77	%	380			468
Unsecured Debentures and Senior Notes(6):
5.0% and 6.625%, due 2013 and 2014	5.06	%	622			622
6.8% and 6.875%, due 2026 and 2027	6.81	%	89			89
Dominion Energy, Inc.:
Secured Senior Notes:
5.03% to 5.78%, due 2013(7)	5.07	%	842			842
7.33%, due 2020(8)			145			159
Tax-Exempt Financings(9):
2.25% to 5.75%, due 2033 to 2042	3.34	%	284			284
Variable rate, due 2041	1.16	%	75			75
Virginia Electric and Power Company total principal (from above)			6,676			6,866
Dominion Resources, Inc. total principal			$	18,988		$	18,745
Fair value hedge valuation(10)			93			105
Securities due within one year(11)	4.53	%	(2,223		)	(1,479		)
Unamortized discount and premium, net			(7		)	23
Dominion Resources, Inc. total long-term debt			$	16,851		$	17,394

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2012.

(2) These financings relate to certain pollution control equipment at Virginia Power's generating facilities. Certain variable rate tax-exempt financings are supported by a $120 million credit facility that terminates in September 2017.

(3) At the option of holders, $510 million of Dominion's 5.25% senior notes due 2033 and $600 million of Dominion's 8.875% senior notes due 2019 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015 and January 2014, respectively.

(4) Convertible into a combination of cash and shares of Dominion's common stock at any time when the closing price of common stock equals 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter. At the option of holders on December 15, 2013 or 2018, these securities are subject to redemption at 100% of the principal amount plus accrued interest. These senior notes have been callable by Dominion since December 15, 2011.

(5) In September 2011, the $500 million6.3% September 2006 hybrids began bearing interest at the three-month LIBOR plus 2.3%, reset quarterly.

(6) Represents debt assumed by Dominion from the merger of its former CNG subsidiary.

(7) Juniper notes issued in 2004 and consolidated in October 2011 due to Dominion becoming the primary beneficiary of this VIE. This amount excludes $18 million and $48 million of unamortized premium in 2012 and 2011, respectively. The debt is non-recourse to Dominion and is secured by Juniper's assets.

(8) Represents debt associated with Kincaid. The debt is non-recourse to Dominion and is secured by the facility's assets ($552 million at December 31, 2012) and revenue. Dominion announced in the third quarter of 2012 that it was pursuing the sale of Kincaid. Dominion anticipates redeeming the notes as a condition to a sale of Kincaid.

(9) Includes debt issued by the Massachusetts Development Finance Agency on behalf of Brayton Point. Dominion announced in the third quarter of 2012 that it was pursuing the sale of Brayton Point.

(10) Represents the valuation of certain fair value hedges associated with Dominion's fixed rate debt.

(11) Includes $23 million of net unamortized premium and fair value hedge valuation in 2012 and $4 million of net unamortized discount in 2011.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2012, were as follows:

	2013			2014			2015			2016			2017			Thereafter			Total
(millions, except percentages)
Virginia Power	$	418		$	17		$	211		$	476		$	679		$	4,875		$	6,676
Weighted-average Coupon	4.88		%	7.73		%	5.39		%	5.27		%	5.44		%	5.26		%
Dominion
Secured Senior Notes	$	852		$	15		$	18		$	20		$	22		$	60		$	987
Unsecured Senior Notes	1,090			1,065			960			1,351			1,303			9,278			15,047
Tax-Exempt Financings	—			—			—			19			75			1,227			1,321
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts	258			—			—			—			—			10			268
Enhanced Junior Subordinated Notes	—			—			—			—			—			1,365			1,365
Total	$	2,200		$	1,080		$	978		$	1,390		$	1,400		$	11,940		$	18,988
Weighted-average Coupon	4.53		%	3.99		%	4.50		%	4.27		%	4.60		%	5.54		%

Dominion's and Virginia Power's short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2012, there were no events of default under these covenants.

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

Convertible Securities

At December 31, 2012, Dominion had $82 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominion's common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. At issuance, the notes were valued at a conversion rate of 27.173 shares of common stock per $1,000 principal amount of senior notes, which represented a conversion price of $36.80. The conversion rate is subject to adjustment without limitation 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 December 31, 2012, the conversion rate had been adjusted to 29.3863 shares, primarily due to individual dividend payments above the level paid at issuance. If the outstanding notes as of December 31, 2012 were all converted, it would result in the issuance of approximately 900 thousand additional shares. In December 2012, Dominion's Board of Directors declared dividends payable March 20, 2013 of 56.25 cents per share of common stock which will increase the conversion rate to 29.5147 effective as of February 26, 2013.

The number of shares included in the denominator of the diluted EPS calculation is calculated as the net shares issuable for the reporting period based upon the average market price for the period. This results in an increase in the average shares outstanding used in the calculation of Dominion's diluted EPS when the conversion price is lower than the average market price of Dominion's common stock over the period, and results in no adjustment when the conversion price exceeds the average market price.

The senior notes are convertible by holders into a combination of cash and shares of Dominion's common stock under any of the following circumstances:

(1) The closing price of Dominion's common stock equals 120% of the applicable conversion price ($40.66 as of February 26, 2013) or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter;

(2) The senior notes are called for redemption by Dominion;

(3) The occurrence of specified corporate transactions; or

(4) The credit rating assigned to the senior notes by Moody's is below Baa3 and by Standard & Poor's is below BBB- or the ratings are discontinued for any reason.

The senior notes were eligible for conversion during 2012 since the closing price of Dominion's common stock was equal to 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days of each quarter. During 2012, approximately $61 million of the contingent convertible senior notes were converted by holders. As of December 31, 2012, the closing price of Dominion's common stock was equal to $40.84 per share or higher for at least 20 out of the last 30 consecutive trading days; therefore, the senior notes are eligible for conversion during the first quarter of 2013. Beginning in 2007, the notes have been eligible for contingent interest if the average trading price as defined in the indenture equals or exceeds 120% of the principal amount of the senior notes. Holders have the right to require Dominion to purchase these senior notes for cash at 100% of the principal amount plus accrued interest in December 2013 or 2018, or if Dominion undergoes certain fundamental changes. The senior notes have been callable by Dominion since December 15, 2011.

Junior Subordinated Notes Payable to Affiliated Trusts

In previous years, Dominion established several subsidiary capital trusts, each as a finance subsidiary of Dominion, which holds 100% of the voting interests. The trusts sold capital securities representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trusts. In exchange for the funds realized from the sale of the capital securities and common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trusts, Dominion issued various junior subordinated notes. The junior subordinated notes constitute 100% of each capital trust's assets. Each trust must redeem its capital securities when their respective junior subordinated notes are repaid at maturity or if redeemed prior to maturity.

In November 2012, Dominion provided notice of redemption for its $258 million7.83% unsecured junior subordinated debentures and all 250 thousand units of the $250 million7.83% Dominion Resources Capital Trust I capital securities due December 1, 2027. At December 31, 2012, the debentures were included in securities due within one year in the Consolidated Balance Sheets. In January 2013, Dominion redeemed the securities at a price of $1,019.58 per capital security plus accrued and unpaid distributions.

The following table provides summary information about the capital securities and junior subordinated notes outstanding as of December 31, 2012:

Date Established	Capital Trusts	Units	Rate		Capital Securities Amount		Common Securities Amount
		(thousands)			(millions)
December 1997	Dominion Resources Capital Trust I(1)	250	7.83	%	$	250	$	7.7
January 2001	Dominion Resources Capital Trust III(2)	10	8.4		10		0.3

Junior subordinated notes/debentures held as assets by each capital trust were as follows:

(1) $258 million-Dominion Resources, Inc. 7.83% Debentures due 12/1/2027.

(2) $10 million-Dominion Resources, Inc. 8.4% Debentures due 1/15/2031.

Interest charges related to Dominion's junior subordinated notes payable to affiliated trusts were $21 million for the years ended December 31, 2012, 2011 and 2010.

Distribution payments on the capital securities are considered to be fully and unconditionally guaranteed by Dominion. Each guarantee agreement only provides for the guarantee of distribution payments on the relevant capital securities to the extent that the trust has funds legally and immediately available to make distributions. The trust's ability to pay amounts when they are due on the capital securities is dependent solely upon the payment of amounts by Dominion when they are due on the junior subordinated notes. Dominion may defer interest payments on the junior subordinated notes on one or more occasions for up to five consecutive years and the related trusts must also defer distributions. If the payment on the junior subordinated notes is deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments, during the deferral period. Also, during any deferral period, Dominion may not make any payments on, redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the junior subordinated notes.

Enhanced Junior Subordinated Notes

In June 2006 and September 2006, Dominion issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids will bear interest at 7.5% per year until June 30, 2016. Thereafter, they will bear interest at the three-month LIBOR plus 2.825%, reset quarterly. Beginning September 30, 2011, the September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly. Previously, interest was fixed at 6.3% per year.

In June 2009, Dominion issued $685 million (including $60 million related to the underwriter's option to purchase additional notes to cover over-allotments) of 8.375% June 2009 hybrids. The June 2009 hybrids are listed on the NYSE under the symbol DRU.

Dominion may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.

Dominion executed RCCs in connection with its issuance of all of the hybrids described above. Under the terms of the RCCs, Dominion covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. 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. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.

In both December 2011 and April 2010, Dominion purchased and canceled approximately $16 million of the September 2006 hybrids. In February 2012, Dominion launched a tender offer to purchase up to $150 million of additional September 2006 hybrids. In the first quarter of 2012, Dominion purchased and canceled approximately $86 million of the September 2006 hybrids primarily as a result of this tender offer, which expired in March 2012. In the second quarter of 2012, Dominion purchased and canceled approximately $2 million of the September 2006 hybrids. All purchases were conducted in compliance with the RCC.

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

XML

Employee Benefit Plans (Fair values of pension and post retirement plan assets by asset category) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	$ 5,553	$ 5,145
Pension Benefits | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	195	85
Pension Benefits | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1,031	928
Pension Benefits | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	524	556
Pension Benefits | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	381	311
Pension Benefits | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	395	271
Pension Benefits | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1,053	870
Pension Benefits | Fixed Income: | U.S. Treasury securities and agency debentures
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	635	696
Pension Benefits | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	72	79
Pension Benefits | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	48	48
Pension Benefits | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	29	16
Pension Benefits | Real estate: | Partnerships
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	321	304
Pension Benefits | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	456	448
Pension Benefits | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	192	243
Pension Benefits | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	221	290
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	2,286	1,974
Pension Benefits | Level 1 | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	1
Pension Benefits | Level 1 | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	927	805
Pension Benefits | Level 1 | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	425	359
Pension Benefits | Level 1 | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	313	253
Pension Benefits | Level 1 | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	228	190
Pension Benefits | Level 1 | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	27	36
Pension Benefits | Level 1 | Fixed Income: | U.S. Treasury securities and agency debentures
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	331	304
Pension Benefits | Level 1 | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1	2
Pension Benefits | Level 1 | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	5	8
Pension Benefits | Level 1 | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	29	16
Pension Benefits | Level 1 | Real estate: | Partnerships
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 1 | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 1 | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 1 | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	2,077	1,886
Pension Benefits | Level 2 | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	195	84
Pension Benefits | Level 2 | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	104	123
Pension Benefits | Level 2 | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	99	197
Pension Benefits | Level 2 | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	68	58
Pension Benefits | Level 2 | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	167	81
Pension Benefits | Level 2 | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1,026	834
Pension Benefits | Level 2 | Fixed Income: | U.S. Treasury securities and agency debentures
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	304	392
Pension Benefits | Level 2 | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	71	77
Pension Benefits | Level 2 | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	43	40
Pension Benefits | Level 2 | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 2 | Real estate: | Partnerships
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 2 | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 2 | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 2 | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1,190	1,285
Pension Benefits | Level 3 | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3 | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3 | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3 | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3 | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3 | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3 | Fixed Income: | U.S. Treasury securities and agency debentures
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3 | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3 | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3 | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 3 | Real estate: | Partnerships
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	321	304
Pension Benefits | Level 3 | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	456	448
Pension Benefits | Level 3 | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	192	243
Pension Benefits | Level 3 | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	221	290
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1,156	1,042
Other Postretirement Plans | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	13	5
Other Postretirement Plans | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	383	326
Other Postretirement Plans | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	66	61
Other Postretirement Plans | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	96	80
Other Postretirement Plans | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	19	13
Other Postretirement Plans | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	161	151
Other Postretirement Plans | Fixed Income: | U.S. Treasury securities and agency debentures
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	282	260
Other Postretirement Plans | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	9	6
Other Postretirement Plans | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	2	2
Other Postretirement Plans | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1	1
Other Postretirement Plans | Real estate: | Partnerships
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	24	24
Other Postretirement Plans | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	58	63
Other Postretirement Plans | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	31	36
Other Postretirement Plans | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	11	14
Other Postretirement Plans | Level 1
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	521	158
Other Postretirement Plans | Level 1 | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 1 | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	378	38
Other Postretirement Plans | Level 1 | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	21	17
Other Postretirement Plans | Level 1 | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	93	77
Other Postretirement Plans | Level 1 | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	11	9
Other Postretirement Plans | Level 1 | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1	2
Other Postretirement Plans | Level 1 | Fixed Income: | U.S. Treasury securities and agency debentures
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	16	14
Other Postretirement Plans | Level 1 | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 1 | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 1 | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1	1
Other Postretirement Plans | Level 1 | Real estate: | Partnerships
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 1 | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 1 | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 1 | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 2
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	511	747
Other Postretirement Plans | Level 2 | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	13	5
Other Postretirement Plans | Level 2 | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	5	288
Other Postretirement Plans | Level 2 | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	45	44
Other Postretirement Plans | Level 2 | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	3	3
Other Postretirement Plans | Level 2 | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	8	4
Other Postretirement Plans | Level 2 | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	160	149
Other Postretirement Plans | Level 2 | Fixed Income: | U.S. Treasury securities and agency debentures
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	266	246
Other Postretirement Plans | Level 2 | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	9	6
Other Postretirement Plans | Level 2 | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	2	2
Other Postretirement Plans | Level 2 | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 2 | Real estate: | Partnerships
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 2 | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 2 | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 2 | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	124	137
Other Postretirement Plans | Level 3 | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3 | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3 | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3 | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3 | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3 | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3 | Fixed Income: | U.S. Treasury securities and agency debentures
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3 | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3 | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3 | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 3 | Real estate: | Partnerships
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	24	24
Other Postretirement Plans | Level 3 | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	58	63
Other Postretirement Plans | Level 3 | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	31	36
Other Postretirement Plans | Level 3 | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	$ 11	$ 14

XML

Commitments and Contingencies (Guarantees, Surety Bonds and Letters of Credit) (Narrative) (Details) (USD $)	Dec. 31, 2012
Guarantor Obligations [Line Items]
Exposure under guarantees	$ 4,206,000,000
Purchased surety bonds	163,000,000
Minimum
Guarantor Obligations [Line Items]
Annual future contributions	4,000,000
Maximum
Guarantor Obligations [Line Items]
Annual future contributions	19,000,000
Standby Letters of Credit
Guarantor Obligations [Line Items]
Authorized standby letters of credit with financial institutions	26,000,000
Third Party and Equity Method Investee
Guarantor Obligations [Line Items]
Estimate of possible loss	92,000,000
Exposure under guarantees	62,000,000
Third Party and Equity Method Investee | Through 2019
Guarantor Obligations [Line Items]
Exposure under guarantees	107,000,000
Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Purchased Surety Bonds	67,000,000
Authorized issuance of standby letters of credit	2,000,000
Virginia Electric and Power Company | Tax-Exempt Financings
Guarantor Obligations [Line Items]
Estimate of possible loss	$ 14,000,000

XML

Commitments and Contingencies (Lease Commitments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Loss Contingencies [Line Items]
2013	$ 79
2014	72
2015	64
2016	55
2017	63
Thereafter	161
Total	494
Virginia Electric and Power Company
Loss Contingencies [Line Items]
2013	26
2014	24
2015	19
2016	15
2017	11
Thereafter	26
Total	$ 121

XML

Fair Value Measurements (Financial Instruments' Carrying Amounts and Fair Values) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	$ 18,988
Long-term debt - VIEs	0		890
Subsidiary preferred stock	257		257
Valuation of certain fair value hedges	93		105
Deferred issuance expenses	2		2
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	16,841	[1]	16,264	[1]
Long-term debt - VIEs	860	[2]	890	[2]
Junior subordinated notes	1,373		1,719
Subsidiary preferred stock	257	[3]	257	[3]
Estimated Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	19,898	[1],[4]	18,936	[1],[4]
Long-term debt - VIEs	864	[2],[4]	892	[2],[4]
Junior subordinated notes	1,430	[4]	1,786	[4]
Subsidiary preferred stock	255	[3],[4]	256	[3],[4]
Virginia Electric and Power Company
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	6,676
Subsidiary preferred stock	257		257
Virginia Electric and Power Company | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	6,669	[1]	6,862	[1]
Subsidiary preferred stock	257	[3]	257	[3]
Virginia Electric and Power Company | Estimated Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	8,270	[1],[4]	8,281	[1],[4]
Subsidiary preferred stock	$ 255	[3],[4]	$ 256	[3],[4]

[1] Includes amounts which represent the unamortized discount and premium. At December 31, 2012, and 2011, includes the valuation of certain fair value hedges associated with Dominion's fixed rate debt, of approximately $93 million and $105 million, respectively.

[2] Includes amounts which represent the unamortized premium.

[3] Includes deferred issuance expenses of $2 million at December 31, 2012 and 2011.

[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. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

XML

Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Schedule of Depreciation Rates

Dominion's and Virginia Power's depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2012	2011	2010
(percent)
Dominion
Generation	2.62	2.68	2.59
Transmission	2.17	2.26	2.24
Distribution	3.17	3.19	3.20
Storage	2.59	2.64	2.75
Gas gathering and processing	2.49	2.52	2.39
General and other	4.55	4.66	4.60
Virginia Power
Generation	2.62	2.68	2.59
Transmission	1.98	2.03	1.94
Distribution	3.32	3.33	3.33
General and other	4.32	4.38	4.28

Schedule of Estimated Useful Life

Dominion's nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:

Asset	Estimated Useful Lives
Merchant generation-nuclear	34-44 years
Merchant generation-other	27-40 years
General and other	5-59 years

XML

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment, Net [Abstract]

Property, Plant and Equipment

PROPERTY, PLANTAND EQUIPMENT

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:

At December 31,	2012		2011
(millions)
Dominion
Utility:
Generation	$	13,707	$	11,793
Transmission	7,799		6,604
Distribution	11,071		10,401
Storage	2,137		2,060
Nuclear fuel	1,277		1,193
Gas gathering and processing	803		727
General and other	803		778
Other-including plant under construction	2,232		3,597
Total utility	39,829		37,153
Nonutility:
Merchant generation-nuclear	1,163		1,108
Merchant generation-other(1)	1,289		2,780
Nuclear fuel	775		847
Other-including plant under construction	1,265		1,102
Total nonutility	4,492		5,837
Total property, plant and equipment	$	44,321	$	42,990
Virginia Power
Utility:
Generation	$	13,707	$	11,793
Transmission	4,261		3,823
Distribution	8,701		8,231
Nuclear fuel	1,277		1,193
General and other	659		631
Other-including plant under construction	2,017		2,946
Total utility	30,622		28,617
Nonutility-other	9		9
Total property, plant and equipment	$	30,631	$	28,626

(1) Amount includes $957 million due to consolidation of a VIE.

Jointly-Owned Power Stations

Dominion's and Virginia Power's proportionate share of jointly-owned power stations at December 31, 2012 is as follows:

	Bath County Pumped Storage Station(1)			North Anna Units 1 and 2(1)			Clover Power Station(1)			Millstone Unit 3(2)
(millions, except percentages)
Ownership interest	60		%	88.4		%	50		%	93.5		%
Plant in service	$	1,024		$	2,392		$	568		$	993
Accumulated depreciation	(521		)	(1,072		)	(192		)	(236		)
Nuclear fuel	—			502			—			456
Accumulated amortization of nuclear fuel	—			(390		)	—			(272		)
Plant under construction	27			77			6			36

(1) Units jointly owned by Virginia Power.

(2) Unit jointly owned by Dominion.

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.

XML

Short-Term Debt And Credit Agreements (Commercial Paper, Bank Loans, and Letters of Credit Outstanding, as well as Capacity Available Under Credit Facilities (Details) (USD $)	Dec. 31, 2012		Dec. 31, 2011
Short term Debt [Line Items]
Facility Limit	$ 3,500,000,000		$ 3,500,000,000
Outstanding Commercial Paper	2,412,000,000	[1]	1,814,000,000	[1]
Outstanding Letters of Credit	26,000,000		36,000,000
Facility Capacity Available	1,062,000,000		1,650,000,000
Weighted-average interest rates of the outstanding commercial paper	0.49%		0.47%
Virginia Electric and Power Company
Short term Debt [Line Items]
Facility Limit	1,250,000,000		1,250,000,000
Outstanding Commercial Paper	992,000,000	[2]	894,000,000	[2]
Outstanding Letters of Credit	2,000,000		15,000,000
Facility Capacity Available	256,000,000		341,000,000
Weighted-average interest rates of the outstanding commercial paper	0.47%		0.46%
Credit facility	120,000,000
Credit Facility 1.5 Billion
Short term Debt [Line Items]
Facility Limit	3,000,000,000	[3]	3,000,000,000	[3]
Outstanding Commercial Paper	2,412,000,000	[3]	1,814,000,000	[3]
Outstanding Letters of Credit	0	[3]	0	[3]
Facility Capacity Available	588,000,000	[3]	1,186,000,000	[3]
Credit facility, to support letters of credit	1,500,000,000
Credit Facility 1.5 Billion | Virginia Electric and Power Company
Short term Debt [Line Items]
Facility Limit	1,000,000,000	[4]	1,000,000,000	[4]
Outstanding Commercial Paper	992,000,000	[4]	894,000,000	[4]
Outstanding Letters of Credit	0	[4]	0	[4]
Facility Capacity Available	8,000,000	[4]	106,000,000	[4]
Credit facility, to support letters of credit	1,500,000,000
Credit Facility 500 million
Short term Debt [Line Items]
Facility Limit	500,000,000	[5]	500,000,000	[5]
Outstanding Commercial Paper	0	[5]	0	[5]
Outstanding Letters of Credit	26,000,000	[5]	36,000,000	[5]
Facility Capacity Available	474,000,000	[5]	464,000,000	[5]
Amount of committed capacity extended	400,000,000
Amount of capacity not extended	100,000,000
Credit Facility 500 million | Virginia Electric and Power Company
Short term Debt [Line Items]
Facility Limit	250,000,000	[6]	250,000,000	[6]
Outstanding Commercial Paper	0	[6]	0	[6]
Outstanding Letters of Credit	2,000,000	[6]	15,000,000	[6]
Facility Capacity Available	$ 248,000,000	[6]	$ 235,000,000	[6]

[1] The weighted-average interest rates of the outstanding commercial paper supported by Dominion's credit facilities were 0.49% and 0.47% at December 31, 2012 and 2011, respectively.

[2] The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.47% and 0.46% at December 31, 2012 and 2011, respectively.

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

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

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

[6] Effective September 2012, the maturity date for $400 million of the $500 million in committed capacity of this credit facility was extended from September 2016 to September 2017. The remaining $100 million continues to have a maturity date of September 2016. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power's current sub-limit under this credit facility can be increased or decreased multiple times per year.