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, 2013

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
2013 Series A 6.125% Corporate Units	New York Stock Exchange
2013 Series B 6% Corporate Units	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 $32.1 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, 2014, Dominion had 581,483,227 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding.

DOCUMENT INCORPORATED BY REFERENCE.

Portions of Dominion’s 2014 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	3
Part I
1.	Business	8
1A.	Risk Factors	23
1B.	Unresolved Staff Comments	29
2.	Properties	29
3.	Legal Proceedings	32
4.	Mine Safety Disclosures	32
	Executive Officers of Dominion	33
Part II
5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
6.	Selected Financial Data	35
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
7A.	Quantitative and Qualitative Disclosures About Market Risk	55
8.	Financial Statements and Supplementary Data	57
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	133
9A.	Controls and Procedures (Dominion)	133
9B.	Other Information	136
Part III
10.	Directors, Executive Officers and Corporate Governance	136
11.	Executive Compensation	137
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	160
13.	Certain Relationships and Related Transactions, and Director Independence	160
14.	Principal Accountant Fees and Services	161
Part IV
15.	Exhibits and Financial Statement Schedules	162

2

Glossary of Terms

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

Abbreviation or Acronym	Definition
2011 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
2013 Biennial Review Order	Order issued by the Virginia Commission in November 2013 concluding the 2011—2012 biennial review of Virginia Power’s base rates, terms and conditions
2014 Proxy Statement	Dominion 2014 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
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
Blue Racer	Blue Racer Midstream, LLC, a joint venture with Caiman
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 1,358 MW combined cycle, natural gas-fired power station under construction in Brunswick County, Virginia
CAA	Clean Air Act
Caiman	Caiman Energy II, LLC
CAIR	Clean Air Interstate Rule
CAO	Chief Accounting Officer
CAP	IRS Compliance Assurance Process
Carson-to-Suffolk line	Virginia Power 60-mile 500 kV transmission line in southeastern Virginia
CD&A	Compensation Discussion and Analysis
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
Cook & Co.	Frederic W. Cook & Co.
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
Corporate Unit	A stock purchase contract and 1/20 interest in a RSN issued by Dominion
Cove Point	Dominion Cove Point LNG, LP
CPCN	Certificate of Public Convenience and Necessity
Crayne interconnect	DTI’s interconnect with Texas Eastern Transmission, LP in Greene County, Pennsylvania
CSAPR	Cross State Air Pollution Rule
CWA	Clean Water Act
DEI	Dominion Energy, Inc.
Dodd-Frank Act	The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOE	Department of Energy

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Abbreviation or Acronym	Definition
Dominion	The legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries (other than Virginia Power) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries
Dominion Direct®	A dividend reinvestment and open enrollment direct stock purchase plan
Dominion Gas	The legal entity, Dominion Gas Holdings, LLC, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Gas Holdings, LLC and its consolidated subsidiaries
Dominion Iroquois	Dominion Iroquois, Inc.
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 Lexington and Dooms substations
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
EPC	Engineering, procurement and construction
EPS	Earnings per share
ERISA	The Employee Retirement Income Security Act of 1974
ERM	Enterprise Risk Management
ERO	Electric Reliability Organization
ESBWR	General Electric-Hitachi’s Economic Simplified Boiling Water Reactor
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
Green Mountain	Green Mountain Power Corporation
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
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
IDA	Industrial Development Authority
Illinois Gas Contracts	A Dominion Retail natural gas book of business consisting of residential and commercial customers in Illinois
INPO	Institute of Nuclear Power Operations
IRC	Internal Revenue Code
Iroquois	Iroquois Gas Transmission System L.P.
IRS	Internal Revenue Service
ISO	Independent system operator
ISO-NE	ISO New England
JD Power	J.D. Power and Associates
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

4

Abbreviation or Acronym	Definition
Kincaid	Kincaid power station
kV	Kilovolt
kWh	Kilowatt-hour
LIBOR	London Interbank Offered Rate
LIFO	Last-in-first-out inventory method
Line TPL-2A	An approximately 11-mile, 30-inch gathering pipeline extending from Tuscarawas County, Ohio to Harrison County, Ohio
Line TL-388	A 37-mile, 24-inch gathering pipeline extending from Texas Eastern, LP in Noble County, Ohio to its terminus at Dominion’s Gilmore Station in Tuscarawas County, Ohio
Line TL-404	An approximately 26-mile, 24- and 30- inch gas gathering pipeline that extends from Wetzel County, West Virginia to Monroe County, Ohio
LNG	Liquefied natural gas
LTIP	Long-term incentive program
Maryland Commission	Maryland Public Service Commission
Massachusetts Municipal	Massachusetts Municipal Wholesale Electric Company
MATS	Utility Mercury and Air Toxics Standard Rule
mcf	thousand cubic feet
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDFA	Massachusetts Development Finance Agency
Meadow Brook-to-Loudoun line	Virginia Power 65-mile 500 kV transmission line that begins in Warren County, Virginia and terminates in Loudoun County, Virginia
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.
MLP	Master limited partnership
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
Natrium	A natural gas and fractionation facility located in Natrium, West Virginia, owned by Blue Racer
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 Carolina Commission	North Carolina Utilities Commission
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
Offshore Wind Advanced Technology Demonstration Program	A research and development cost share program funded by the DOE to identify innovations that will establish offshore wind as a cost-effective renewable energy resource and successfully implement these technologies on a demonstration-scale project by the end of 2017
Ohio Commission	Public Utilities Commission of Ohio
OSHA	Occupational Safety and Health Administration
PBGC	Pension Benefit Guaranty Corporation
Peoples	The Peoples Natural Gas Company
Philadelphia Utility Index	Philadelphia Stock Exchange Utility Index
Pipeline Safety Act	The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011

5

Abbreviation or Acronym	Definition
PIPP	Percentage of Income Payment Plan deployed by East Ohio
PIR	Pipeline Infrastructure Replacement program deployed by East Ohio
PJM	PJM Interconnection, L.L.C.
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, as amended in 2013
REIT	Real estate investment trust
RGGI	Regional Greenhouse Gas Initiative
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
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 T1	A rate adjustment clause to recover the difference between revenues produced from transmission rates included in base rates, and the new total revenue requirement developed annually for the rate years effective September 1
Rider W	A rate adjustment clause associated with the recovery of costs related to Warren County
Riders C1A and C2A	Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in DSM cases
ROE	Return on equity
ROIC	Return on invested capital
RPS	Renewable Portfolio Standard
RSN	Remarketable subordinated note
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
Solar Partnership Program	A solar generation program in Virginia to study the impact and assess the benefits of solar generation through construction and operation of up to 30 MW of Virginia Power-owned solar panels
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
UAO	Unilateral Administrative Order
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 Wind Energy Area	Approximately 113,000 acres of federal land 24 nautical miles off the Virginia coast designated for offshore wind energy generation

6

Abbreviation or Acronym	Definition
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
Western System	Collection of approximately 212 miles of various diameter natural gas pipelines and three compressor stations in Ohio
Yorktown	Yorktown power station

7

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 23,600 MW of generating capacity, 6,400 miles of electric transmission lines, 57,000 miles of electric distribution lines, 10,900 miles of natural gas transmission, gathering and storage pipeline and 21,900 miles of gas distribution pipeline, exclusive of service lines. Dominion presently serves nearly 6 million utility and retail energy customers in 15 states and operates one of the nation’s largest underground natural gas storage systems, with approximately 947 bcf of storage capacity.

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. With this investment, Dominion expects 80% to 90% of future earnings from its primary operating segments to come from regulated and long-term contracted businesses.

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 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 and electric transmission and distribution networks. Investments to gather and process natural gas production from the Utica Shale formation, in eastern Ohio and western Pennsylvania, are being made by the Blue Racer joint venture.

In September 2013, Dominion announced the formation of Dominion Gas, a first tier wholly-owned subsidiary holding company for the majority of Dominion’s regulated natural gas businesses. Specifically, Dominion transferred direct ownership of East Ohio, DTI and Dominion Iroquois, the latter of which holds a 24.72% general partnership interest in Iroquois, to Dominion Gas on September 30, 2013. Dominion Gas will be the primary financing entity for Dominion’s regulated natural gas businesses and expects to become an SEC registrant in 2014.

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

Dominion has transitioned 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 2013 and the ongoing exit of natural gas trading and certain energy marketing activities. Dominion’s nonregulated

operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations. 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, 2013, Dominion had approximately 14,500 full-time employees, of which approximately 5,300 employees are subject to collective bargaining agreements. As of December 31, 2013, Virginia Power had approximately 6,700 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, http://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.

8

ACQUISITIONS AND DISPOSITIONS

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

SALE OF BRAYTON POINT, KINCAID AND EQUITY METHOD INVESTMENT IN ELWOOD

In August 2013, Dominion completed the sale of Brayton Point, Kincaid and its equity method investment in Elwood to Energy Capital Partners and received proceeds of approximately $465 million, net of transaction costs. The historical results of Brayton Point’s and Kincaid’s 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.

SALE OF E&P PROPERTIES

In April 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.

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.

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 discontinued, which is discussed in Note 3 to the Consolidated Financial Statements. In addition, Corporate and Other includes specific items attributable to Dominion’s other 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
Dominion Generation	Regulated electric fleet		X		X
	Merchant electric fleet		X
	Nonregulated retail energy marketing (electric and gas)(1)		X
Dominion Energy	Gas transmission and storage		X
	Gas distribution and storage		X
	LNG services		X
	Producer services		X

(1) As a result of Dominion’s decision to realign its business units effective for 2013 year-end reporting, nonregulated retail energy marketing operations were moved from DVP to the Dominion Generation segment.

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 Dominion and 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 announced its five-year investment plan, which includes spending approximately $4.8 billion from 2014 through 2018 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.

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. Metrics used in measuring electric reliability and customer service were modified in 2013 to align with industry standards. Utilizing the new standard, Virginia Power continues to see improvement as SAIDI performance results were 106 minutes at the end of 2013, down from the three-year average of 130 minutes. Virginia Power’s customer satisfaction improved year over year when compared to peer utilities in the South Large segment of JD Power’s rankings.

9

Based on the annual JD Power Customer Satisfaction results, DVP improved customer satisfaction and moved up three positions in the South Large segment ranking. 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 Dominion’s Facebook, Twitter or internet website. In the future, safety, electric service reliability and customer service will remain key focus 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 safety, operational performance, NERC compliance and execution of PJM’s RTEP.

Dominion’s nonregulated retail energy marketing operations are now reflected in the Dominion Generation segment. See Note 25 to the Consolidated Financial Statements for additional information.

COMPETITION

DVP Operating Segment—Dominion and Virginia Power

There is no competition for electric distribution service within Virginia Power’s service territory in Virginia and North Carolina and no such competition is currently permitted. Additionally, there traditionally has been no competition for transmission service in the PJM region and Virginia Power’s electric transmission facilities are integrated into PJM. However, competition from non-incumbent PJM transmission owners for development, construction and ownership of certain transmission facilities in Virginia Power’s service territory is now permitted pursuant to FERC Order 1000, subject to state and local siting and permitting approvals. This could result in additional competition to build transmission lines in Virginia Power’s service area in the future and could allow Dominion to seek opportunities to build facilities in other service territories.

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 2013 Biennial Review Order.

PROPERTIES

Virginia Power has approximately 6,400 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.

As a part of PJM’s RTEP process, PJM authorized the following material reliability projects (including estimated cost):

Ÿ Mt. Storm-to-Doubs line ($350 million);

Ÿ Surry-to-Skiffes Creek-to-Whealton lines ($155 million);

Ÿ Dooms-to-Lexington line ($112 million);

Ÿ Waxpool-Brambleton-BECO line ($49 million);

Ÿ Harrisonburg-to-Endless Caverns line ($66 million);

Ÿ Radnor Heights Project ($81 million);

Ÿ Dooms-to-Bremo line ($65 million);

Ÿ Loudoun voltage regulation project ($70 million); and

Ÿ Landstown voltage regulation project ($60 million).

In addition, Virginia Power’s electric distribution network includes approximately 57,000 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.

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 catastrophic 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.

Dominion Generation

The Dominion Generation Operating Segment of Virginia Power includes the generation operations of the Virginia Power regu-

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lated 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. The Dominion Generation Operating Segment of Dominion includes Virginia Power’s generation facilities and its related energy supply operations as well as the generation operations of Dominion’s merchant fleet and energy marketing and price risk management activities for these assets and Dominion’s nonregulated retail energy marketing operations.

Dominion Generation’s five-year electric utility investment plan includes spending approximately $3.3 billion from 2014 through 2018 to develop, finance and construct new generation capacity to meet growing electricity demand within its utility service territory. Significant projects under construction include Warren County and Brunswick County, which are estimated to cost approximately $1.1 billion and $1.3 billion, excluding financing costs, respectively. See Properties for additional information on these and other utility projects.

In addition, Dominion’s merchant fleet has acquired and developed several renewable generation projects, which began commercial operations during the fourth quarter of 2013. The total cost of the projects is approximately $200 million, excluding financing costs, and includes a fuel cell generation facility in Connecticut and solar generation facilities in Indiana, Georgia, and Connecticut. The output of these facilities is sold under long-term power purchase agreements with terms ranging from 15 to 25 years.

Earnings for the Dominion 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. Base rates for the Virginia jurisdiction are set using a modified cost-of-service rate model, and are generally designed to allow an opportunity to recover the cost of providing utility service and earn a reasonable return on investments used to provide that service. Earnings variability may arise when revenues are impacted by factors not reflected in current rates, such as the impact of weather on customers’ demand for services. Likewise, earnings may reflect variations in the timing or nature of expenses as compared to those contemplated in current rates, such as labor and benefit costs, capacity expenses, and the timing, duration and costs of scheduled and unscheduled outages. 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. The cost of new generation facilities is generally recovered through rate adjustment clauses in Virginia. Variability in earnings from rate adjustment clauses reflects changes in the authorized ROE and the carrying amount of these facilities, which are largely driven by the timing and amount of capital investments, as well as depreciation. 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 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 the electric price volatility of its merchant fleet by hedging a substantial portion of its expected near-term energy sales with derivative instruments. 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 led to its decision to sell or retire certain merchant generation assets, which is discussed in Properties. 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.

Dominion’s retail energy marketing operations compete in nonregulated energy markets. The retail business requires limited capital investment and currently has approximately 190 employees. 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. In January 2014, Dominion announced it will exit the electric retail energy marketing business, but will retain its natural gas and energy-related products and services retail energy marketing businesses.

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 provides 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 assets operate within functioning RTOs and primarily compete on the basis of price.

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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.

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 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 and Note 13 to the Consolidated Financial Statements 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 approximately 19,600 MW. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro, renewables, and power purchase agreements. Virginia Power’s generation facilities are located in Virginia, West Virginia and North Carolina and serve load in Virginia and northeastern North Carolina.

Virginia Power is developing, financing, and constructing new generation capacity to meet growing electricity demand within its service territory. 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.

Ÿ In August 2013, the Virginia Commission authorized the construction of Brunswick County, which is estimated to cost approximately $1.3 billion, excluding financing costs. It is expected to generate 1,358 MW when operational. Construction of the facility commenced in the third quarter of 2013 with commercial operations expected to begin in spring 2016. Brunswick County is expected to offset the expected

reduction in capacity caused by the planned retirement of coal-fired units at Chesapeake by 2015 and at Yorktown as early as 2016, primarily due to the cost of compliance with MATS.

Ÿ During 2013, Virginia Power converted three coal-fired Virginia generating stations to biomass. The conversions of the power stations in Altavista, Hopewell and Southampton County increased Dominion’s renewable generation by 153 MW and cost approximately $157 million, excluding financing costs. The Altavista, Hopewell and Southampton County power stations commenced commercial operations using biomass as their fuel in July, October, and November 2013, respectively.

Ÿ In September 2013, the Virginia Commission authorized Virginia Power to convert Bremo Units 3 and 4 from coal to natural gas. This project will 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 completed in 2014 in compliance with the Virginia City Hybrid Energy Center air permit.

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

Ÿ 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

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, 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 ceased power production in the second quarter of 2013 and commenced decommissioning activities. In addition, 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. Dominion completed the sale of these power stations in the third quarter of 2013.

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Following these divestitures, the generation capacity of Dominion’s merchant fleet totals approximately 4,000 MW. The generation mix is diversified and includes nuclear, gas, and renewables. Merchant generation facilities are located in Connecticut, Indiana, Georgia, Pennsylvania, Rhode Island and West Virginia, with a majority of that capacity concentrated in New England.

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.

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 domestic suppliers.

Dominion Generation’s biomass supply is obtained through long-term contracts and short-term spot agreements from local 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 provides for reliable natural gas deliveries 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 and ISO-NE spot markets to satisfy physical forward sale requirements as part of its merchant generation operations. Prior to the shutdown of Kewaunee and divestiture of its other Midwest generation facilities, Dominion Generation also occasionally purchased electricity from the MISO spot market.

Dominion Generation Operating Segment—Virginia Power

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

Source	2013			2012			2011
Nuclear(1)		33	%		33	%		28	%
Purchased power, net		21			27			33
Coal(2)		29			22			26
Natural gas		16			17			12
Other(3)		1			1			1
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 2013 Virginia in-system generation was $33.00 per MWh.

(3) Includes oil, hydro and biomass.

Dominion Generation Operating Segment-Dominion

The supply of electricity to serve Dominion’s nonregulated 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

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.

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.

NUCLEAR DECOMMISSIONING

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 are placed into trusts and are 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-

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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, if needed, 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 to five 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 two licensed, operating nuclear reactors at Millstone in Connecticut. A third Millstone unit ceased operations before Dominion acquired the power station. In May 2013, Dominion ceased operations at its single unit Kewaunee nuclear power station in Wisconsin and commenced 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 decommissioning 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 minimum 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 for Surry, North Anna and Millstone in 2009 and for Kewaunee in 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 (2013 dollars)(1)		Funds in trusts at December 31, 2013		2013 contributions to trusts
(dollars in millions)
Surry
Unit 1		2032	$	497	$	501	$	0.6
Unit 2		2033		521		493		0.6
North Anna
Unit 1(2)		2038		443		398		0.4
Unit 2(2)		2040		456		373		0.3
Total (Virginia Power)				1,917		1,765		1.9
Millstone
Unit 1(3)		n/a		441		419		—
Unit 2		2035		556		522		—
Unit 3(4)		2045		596		512		—
Kewaunee								—
Unit 1(5)		n/a		651		685		—
Total (Dominion)			$	4,161	$	3,903	$	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 and Green Mountain. Decommissioning cost is shown at Dominion’s ownership percentage. At December 31, 2013, the minority owners held approximately $32 million of trust funds related to Millstone Unit 3 that are not reflected in the table above.

(5) Permanently ceased operations in 2013.

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

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The gas transmission pipeline and storage business serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in Dominion Energy’s gas transmission pipeline and storage business is its gas gathering and extraction activity, which sells extracted products at market rates. Dominion Energy’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. Dominion has received DOE approval to export LNG from Cove Point and is awaiting other federal and state regulatory approvals 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 concentrates on building new gathering, processing, fractionation and NGL transportation assets as the development of the Utica Shale formation increases. Dominion has contributed or sold various assets to the joint venture. See Note 9 to the Consolidated Financial Statements for more information.

In September 2013, Dominion announced the formation of Dominion Gas, a first tier wholly-owned subsidiary holding company for the majority of Dominion’s regulated natural gas businesses. Also in September 2013, Dominion announced its plans to form an MLP in 2014 by contributing certain of its midstream natural gas assets to the MLP initially and over time. See General above for more information.

Dominion Energy’s five-year investment plan includes spending approximately $3.4 billion to $3.8 billion, exclusive of financing costs, from 2014 through 2018 for its Cove Point export project. Its five-year investment plan also includes spending approximately $2.1 billion to upgrade existing infrastructure or add new pipelines to meet growing energy needs within its service territory and maintain reliability.

Revenue provided by Dominion Energy’s regulated gas transmission and storage and LNG operations is based primarily on rates established by FERC. Additionally, Dominion Energy 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.

Revenue from extraction and fractionation operations largely results from the sale of commodities at market prices. For DTI’s extraction and processing plants, Dominion purchases the wet gas product from producers and retains some or all of the extracted NGLs as compensation for its services. This exposes Dominion Energy to commodity price risk for the value of the spread between the NGL products and natural gas. In addition, Dominion Energy has volumetric risk since gas deliveries to DTI’s facilities are not under long-term contracts. However, the extraction

and fractionation operations within Dominion Energy’s Blue Racer joint venture are managed under long-term fee-based contracts, which minimizes commodity and volumetric risk. Variability in earnings largely results from changes in the quantities of natural gas and NGLs supplied to DTI’s facilities and commodity prices.

East Ohio utilizes 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.

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.

DTI’s extraction and fractionation operations face competition in obtaining natural gas supplies for its processing and related services. Numerous factors impact any given customer’s choice of processing services provider, including the location of the facilities, efficiency and reliability of operations, and the pricing arrangements offered.

Retail competition for gas supply exists to varying degrees in the two states in which Dominion Energy’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 April 2013, East Ohio began to fully exit the merchant function for its nonresidential customers, 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, 2013, approximately 1 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice program. West Virginia does not allow 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 21,900 miles of pipe, exclusive of service lines. The rights-

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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 10,900 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy owns gas processing and fractionation facilities in West Virginia with a total processing capacity of 280,000 mcf per day and fractionation capacity of 580,000 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 140 compressor stations with approximately 830,000 installed compressor horsepower.

In December 2013, DTI closed on agreements with two natural gas producers to convey approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. See Note 10 to the Consolidated Financial Statements for further information.

Dominion is pursuing a liquefaction project at Cove Point, which would enable the facility to liquefy domestically-produced natural gas for export as LNG. In September 2013, the DOE conditionally authorized Dominion to export LNG from Cove Point to non-free trade agreement countries. Subject to environmental review by FERC and final FERC and Maryland Commission approval, the Cove Point facility is authorized to export at a rate of 770 million cubic feet of natural gas per day for a period of 20 years. The DOE previously authorized Dominion to export to countries with free trade agreements. Following receipt of regulatory and other approvals, construction of liquefaction facilities could begin in 2014 with an in-service date in 2017. See Item 2. Properties for more information about the Cove Point facility.

In January 2011, Dominion announced the development of a natural gas processing and fractionation facility in Natrium, West Virginia. This first phase of the project is fully contracted, was completed in the second quarter of 2013 and was contributed to Blue Racer in the third quarter of 2013 resulting in an increased equity method investment in Blue Racer of $473 million. In September 2013, the Natrium facility was shut down following a fire at the plant and returned to service in January 2014.

In May 2012, Dominion began construction of the G-150 pipeline project, which is designed to transport approximately 27,000 barrels per day of NGLs from the Natrium facility to an interconnect with the ATEX line of Enterprise near Follansbee, West Virginia. Transportation services on the pipeline will be subject to FERC regulation pursuant to the Interstate Commerce

Act. In November 2013, FERC granted Dominion’s petition for declaratory order and approved Dominion’s proposed (1) general rate structure, (2) rate and terms for committed shippers, and (3) rate design for uncommitted shippers. Dominion NGL Pipelines, LLC (now Blue Racer NGL Pipelines, LLC), the owner of the 58-mile pipeline and associated equipment, was contributed in January 2014 to Blue Racer prior to commencement of service, resulting in an increased equity method investment of $155 million.

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

In September 2013, DTI executed binding precedent agreements with several local distribution company customers for the New Market Project. The project is expected to cost approximately $159 million and provide 112,000 dekatherms per day of firm transportation service from Leidy, Pennsylvania to interconnects with Iroquois and Niagara Mohawk Power Corporation’s distribution system in the Albany, New York market. In 2014, DTI expects to file an application to request FERC authorization to construct and operate the project facilities, which are expected to be in service in the fourth quarter of 2016.

In October 2013, DTI executed a binding precedent agreement with CNX Gas Company LLC for the Clarington Project. The project is expected to cost approximately $78 million and provide 250,000 dekatherms per day of firm transportation service from central West Virginia to Clarington, Ohio. In 2014, DTI expects to file an application to request FERC authorization to construct and operate the project facilities, which are expected to be in service in the fourth quarter of 2016.

In March 2013, FERC approved DTI’s $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 previously 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 commenced in the second quarter of 2013 and the project was placed in service in November 2013.

In March 2013, DTI received FERC approval 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 the Crayne interconnect 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. Construction commenced in the second quarter of 2013 and the project was placed in service in November 2013.

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.

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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 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 placed into service in the fourth quarter of 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.

In July 2013, East Ohio signed long-term precedent agreements with two customers to move 300,000 dekatherms per day of processed gas from the outlet of new gas processing facilities in Ohio to interconnections with multiple interstate pipelines. The Western Access Project would provide system enhancements to facilitate the movement of processed gas over East Ohio’s system and is expected to be completed by November 2014, and cost approximately $90 million.

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 aggregates and transports.

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 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 four major elements:

Ÿ Compliance with applicable environmental laws, regulations and rules;

Ÿ Conservation and load management;

Ÿ Renewable generation development; and

Ÿ Improvements in other energy infrastructure.

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. 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

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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 and load management play 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 10% of the electric energy consumed in 2006 through the implementation of conservation programs. Additional legislation in 2009 added definitions of peak-shaving and energy efficiency programs, and allowed for a margin on operating expenses and recovery of revenue reductions related to energy efficiency programs.

Virginia Power’s DSM programs provide important incremental steps toward achieving the voluntary 10% energy conservation goal through activities such as energy audits and incentives for customers to upgrade or install certain energy efficient systems. The DSM programs began in Virginia in 2010 and in North Carolina in 2011.

Virginia Power currently offers the following DSM programs in Virginia:

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 Residential Bundle Program: a bundle of four residential programs to be available with incentives 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;

Ÿ Non-Residential Energy Audit Program: an on-site energy audit providing qualified non-residential customers with energy assessments;

Ÿ Non-Residential Duct Testing & Sealing: an incentive for qualified non-residential customers to seal poorly performing duct and air distribution systems in qualifying non-residential facilities; and

Ÿ Non-Residential Distributed Generation: a program for qualified non-residential customers that provides an incentive to curtail load by operating customer-owned backup generation when requested by Virginia Power during periods of peak demand.

In August 2013, Virginia Power requested approval from the Virginia Commission to launch three new energy efficiency DSM programs as well as requested additional measures to enhance the

current Non-Residential Energy Audit Program. The three proposed DSM programs are the Non-Residential Lighting Systems & Controls Program, the Non-Residential Heating & Cooling Efficiency Program, and the Non-Residential Solar Window Film Program. This regulatory matter is still pending.

Virginia Power currently offers the following programs in North Carolina:

Ÿ Residential Low Income Program (described above);

Ÿ Residential Air Conditioner Cycling Program (described above);

Ÿ Residential Bundle Program (described above);

Ÿ Commercial Heating, Ventilating and Air Conditioning Upgrade Program: incentives for non-residential customers to upgrade existing or install new heating and/or cooling systems to higher efficiency models;

Ÿ Commercial Lighting Program: incentives for non-residential customers to upgrade existing or new lighting systems to higher efficiency models;

Ÿ Non-Residential Energy Audit Program (described above); and

Ÿ Non-Residential Duct Testing & Sealing Program (described above).

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

Virginia Power continues to upgrade meters to AMI, also referred to as smart meters, in portions of Virginia. The AMI meter upgrades are part of an ongoing project that will help Virginia Power further evaluate 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.

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. In 2013, Virginia Power converted three coal-fired Virginia generating power stations to biomass, which increased its renewable generation by 153 MW.

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Virginia Power is considering the development of a commercial offshore wind generation project through a federal land lease off the Virginia coast.

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.

In addition, during 2013 Dominion acquired and developed 42 MW of renewable energy projects, which includes solar generation facilities in Indiana, Georgia, and Connecticut.

Virginia Power is implementing the Solar Partnership Program. The Virginia Commission requires the project be constructed and operated at a cost to customers not to exceed $80 million. In 2013, Virginia Power announced that Old Dominion University and Canon Virginia’s Industrial Resource Technologies had been selected as participants in the program. During 2014, Virginia Power is planning to develop six to ten additional sites with a total capacity of up to 10 MW.

In March 2013, the Virginia Commission approved Rate Schedule SP, under which Virginia Power will purchase 100% of the energy output from up to a combined 3 MW of customer-owned solar distributed generation facilities, including all environmental attributes and associated renewable energy credits, at a fixed price of $0.15 per kWh for five years. This fixed price has two components: an avoided cost component (including line losses) determined using Virginia Power’s Rate Schedule 19 and recovered through Virginia Power’s fuel factor, and a voluntary environmental contribution component.

In December 2013, Dominion placed into service a fuel cell facility in Connecticut that produces approximately 15 MW of electricity using a reactive process that converts natural gas into electricity.

See Future Issues and Other Matters in Item 7. MD&A and Note 22 to the Consolidated Financial Statements for additional information.

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 implemented a program designed to encourage customers to charge their electric vehicles at night when electricity demand is lower. The Virginia Commission has approved this program through November 2016.

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 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, implementing technologies to minimize natural gas releases 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 2,800 MW of non-emitting generation and approximately 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 153 MW of renewable biomass by completing the conversion of three coal-fired power stations.

Ÿ Virginia Power expects to complete the conversion of Bremo Units 3 and 4 from coal to natural gas during 2014.

Ÿ Dominion has over 500 MW of onshore wind energy in operation or development.

Ÿ Virginia Power is constructing the natural gas-fired Warren County and Brunswick County power stations.

Ÿ Virginia Power plans to retire the coal-fired units at Chesapeake by 2015 and at Yorktown as early as 2016.

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 Virginia Power is implementing the Solar Partnership Program as mentioned above.

Ÿ Virginia Power is considering the development of a commercial offshore wind generation project through a federal land lease off the Virginia coast.

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

Ÿ In 2013, Dominion constructed a 15 MW fuel cell power generating facility in Bridgeport, Connecticut.

Ÿ In 2013, Dominion sold Brayton Point, a coal-and fuel oil-fired merchant power station, and Kincaid, a coal-fired merchant power station.

Ÿ In 2013, Dominion acquired and developed 42 MW of solar generation facilities in Indiana, Georgia, and Connecticut as mentioned above.

Ÿ Dominion has designed control programming to minimize the amount of natural gas released into the atmosphere when a station shutdown occurs, such as would occur for routine maintenance and repairs.

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Ÿ Dominion is avoiding the use of natural gas-powered turbine starters on new turbine installations, employing electric starters, where feasible.

Ÿ Dominion is conducting directed inspections and repairs and tracking findings and actions in an emissions tracking system.

Dominion also developed a comprehensive GHG inventory for calendar year 2012. For Dominion Generation, Dominion’s and Virginia Power’s direct CO₂ equivalent emissions, based on equity share (ownership), were approximately 36.2 million metric tonnes and 24.4 million metric tonnes, respectively, in 2012, compared to 42.1 million metric tonnes and 25.9 million metric tonnes, respectively, in 2011. The decrease in emissions from 2011 to 2012 is largely due to an increase in natural gas usage, less reliance on coal, and more renewable generation. For the DVP operating segment’s electric transmission and distribution operations, direct CO₂ equivalent emissions for 2012 were 76,143 metric tonnes, representing a decrease of almost 50% from 2011 due to a decrease in gas leakage from insulating equipment. For 2012, DTI’s (including Cove Point) direct CO₂ equivalent emissions were approximately 1.0 million metric tonnes, and Hope’s and East Ohio’s direct CO₂ equivalent emissions were approximately 0.9 million metric tonnes, showing a 58% decrease from 2011. Dominion’s GHG inventory 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 2012, Dominion’s 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 39% and 28%, respectively. During such time period, the capacity of Dominion’s and Virginia Power’s electric generation fleet has grown. The Companies do not yet have final 2013 emissions data.

Alternative Energy Initiatives

AES conducts research in the renewable and alternative energy technologies sector and supports strategic investments, such as the Tredegar Solar Fund I, as discussed below, to advance Dominion’s degree of understanding of such technologies. AES also 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 2013, Virginia Power completed the initial engineering, design and permitting work for a wind turbine demonstration facility as part of the DOE’s Offshore Wind Advanced Technology Demonstration Program. The proposed 12 MW facility would generate power via two turbines located approximately 24 miles off the coast of Virginia, adjacent to the Virginia Wind Energy Area where Virginia Power is considering development of a commercial offshore wind generation project. Dominion has also conducted a number of studies to evaluate potential transmission solutions for delivering offshore wind resources to its customers. One study determined the existing onshore transmission system has the capability to interconnect up to 4,500 MW of offshore wind energy and another evaluated options for high-voltage subsea transmission lines that would connect offshore wind generation facilities to the onshore transmission system.

In 2013, 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.

In 2012, Dominion formed Tredegar Solar Fund I, an entity managed by the AES department and focused on unregulated residential solar projects. This fund owns residential roof-top solar systems that are originated and administered by Clean Power Finance, Inc., a provider of solar finance products, in which Dominion has a small indirect equity investment. The systems are subject to power purchase agreements with third parties. In December 2013, Dominion’s Board of Directors approved an incremental investment in this fund, for a total authorized investment of $90 million. This fund currently has originations in process of approximately $32 million and assets in service of approximately $36 million.

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.

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 CPCNs 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

Under the Regulation Act enacted in 2007, Virginia Power’s base rates are set by a process that allows the recovery of operating costs and an ROIC. The Virginia Commission reviews and has the ability to adjust 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. 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 determination by the Virginia Commission that Virginia Power has exceeded its authorized level of earnings 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.

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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; and it provides for enhanced returns on capital expenditures on specific new generation projects. The Regulation Act also continues statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.

Legislation enacted in February 2013 amended the Regulation Act prospectively, including elimination of the 50 basis points RPS ROE incentive. In addition, ROE incentives for newly proposed generation projects were eliminated, except for nuclear and offshore wind projects, which were reduced from the previous 200 basis points ROE incentive to 100 basis points. In addition, through the 2013 amendments, the Virginia Commission has the discretion to increase or decrease a utility’s authorized ROE based on the utility’s performance consistent with Virginia Commission precedent that existed prior to 2007. The legislation included 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 previous 60% level beginning with the biennial review for 2013-2014 to be filed in 2015.

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, such decisions may adversely affect Virginia Power’s results of operations, financial condition and cash flows.

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. 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.

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 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 requires those customers to choose a retail supplier or be assigned to one at a monthly variable rate set by the supplier. At December 31, 2013, 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 allow 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

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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 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 and export facilities and interstate natural gas pipeline and storage facilities.

Dominion’s interstate gas transmission and storage activities are 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

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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 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 businesses) or market prices (in unregulated businesses), 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 and 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 Note 22 to the Consolidated Financial Statements 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 above 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. See Item 1A. Risk Factors for additional information.

Item 1A. Risk Factors

Dominion 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. In addition, severe weather, including hurricanes, floods 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, dis-

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tribution 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. 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, including tax 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 legis-

lation 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 or its interpretation of market rules, 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, conversion 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, conversion and expansion projects have been announced and additional projects may be considered in the 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, conversion 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. Start-up and operational issues can arise in connection with the commencement of commercial operations at our facilities, including but not limited to commencement of commercial operations at our power generation facilities following expansions and fuel type conversions to natural gas and biomass. Such issues may include failure to meet specific operating parameters, which may require adjustments to meet or amend these operating parameters. Additionally, Dominion and Virginia Power may not be able to timely

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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, conversion 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. Certain facilities have become uneconomical to operate and have been shut down, converted to new fuel types or sold. These types of events could occur again 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. Additional regulation of air quality and GHG emissions under the CAA may be imposed on the natural gas sector, including rules to limit methane leakage. Compliance with GHG emission reduction requirements may require the retrofit or replacement of equipment or could otherwise increase the cost to operate and maintain our facilities. 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, Rhode Island has implemented regulations requiring reductions in CO² emissions through RGGI, a cap and trade program covering CO² emissions from power plants in the Northeast.

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.

Dominion’s and Virginia Power’s operations are subject to operational hazards, equipment failures, supply chain disruptions and personnel issues which could negatively affect the Companies. 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. The Companies’ businesses are dependent upon sophisticated information technology systems and network infrastructure, the failure of which could prevent

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them from accomplishing critical business functions. 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.

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.

In addition, there are many risks associated with the Companies’ operations, including nuclear accidents, fires, explosions, uncontrolled release of natural gas and other environmental hazards, pole strikes, electric contact cases and avian impacts. Such incidents could result in loss of human life or injuries among employees, customers or the public in general, environmental pollution, damage or destruction of facilities or business interruptions and associated public or employee safety impacts, loss of revenues, increased liabilities, heightened regulatory scrutiny and reputational risk.

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 to provide the NGLs that it separates into marketable products. 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 contracted to supply natural gas to the Natrium natural gas processing and fractionation facility are subject to contractual minimum fee payments. Natrium is owned by Blue Racer. If producers were to decrease the supply of natural gas or NGLs for any reason to systems and facilities in which Dominion has an interest, Dominion could experience lower revenues to the extent it is unable to replace the lost volumes on similar terms.

The development, construction and operation of the Cove Point liquefaction project would involve significant risks. As described in greater detail in Future Issues and Other Matters, Dominion intends to invest significant financial resources in the liquefaction project, subject to receipt of required regulatory approvals. An inability to obtain financing or otherwise provide liquidity for the project on acceptable terms could negatively affect Dominion’s financial condition, cash flows, the project’s anticipated financial results and/or impair Dominion’s ability to execute the business plan for the project as scheduled.

The project remains subject to FERC and other federal and state approvals. The DOE has authorized Dominion to export LNG to non-free trade agreement countries, however, all DOE export licenses are subject to review and possible withdrawal should the DOE conclude that such export authorization is no longer in the public interest, which could have a material adverse effect on the construction or operation of the facility. In addition, the liquefaction project has been the subject of litigation which, although decided in Dominion’s favor, is the subject of an appeal. A delay in receipt of project approvals or an adverse ruling by an appellate court could adversely affect Dominion’s ability to execute its business plan.

There is limited recent industry experience in the U.S. regarding the construction or operation of large liquefaction projects. The construction of the facility is expected to take several years, will be confined within a limited geographic area and could be subject to delays, cost overruns, labor disputes and other factors that could cause the total cost of the project to exceed the anticipated amount and adversely affect Dominion’s financial performance and/or impair Dominion’s ability to execute the business plan for the project as scheduled.

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There are significant customer risks associated with the project. The terminal service agreements are subject to certain conditions precedent, including receipt of regulatory approvals. Dominion will also be exposed to counterparty credit risk. While the counterparties’ obligations are supported by parental guarantees and letters of credit, there is no assurance that such credit support would be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under either agreement resulting in a judgment in Dominion’s favor, Dominion may need to seek to enforce a final U.S. court judgment in a foreign tribunal, which could involve a lengthy process.

Assuming current commodity price trends continue, if Dominion is unable to pursue the liquefaction project, Dominion may not be able to offset the prospective revenue reductions associated with the existing import contracts as described in Future Issues and Other Matters, which could have a negative impact on its results of operations.

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.

Dominion’s and Virginia Power’s financial results can be adversely affected by various factors driving demand for electricity and gas. Technological advances required by federal laws mandate new levels of energy efficiency in end-use devices, including lighting, furnaces and electric heat pumps and could lead to declines in per capita energy consumption. Additionally, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Further, Virginia Power’s business model is premised upon the cost efficiency of the production, transmission and distribution of large-scale centralized utility

generation. However, advances in distributed generation technologies, such as solar cells, gas microturbines and fuel cells, may make these alternative generation methods competitive with large-scale utility generation, and change how customers acquire or use our services.

Reduced energy demand or significantly slowed growth in demand due to customer adoption of energy efficient technology, conservation, distributed generation or regional economic conditions, unless substantially offset through regulatory cost allocations, could adversely impact the value of the Companies’ business activities.

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, joint venture partners or other third parties may adversely affect the Companies’ financial results.

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 for hedging exposures from its business units. The Companies could recognize financial losses on these contracts,

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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 securities 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, including rules regarding margin requirements for non-cleared swaps. 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 swaps provisions of the Dodd-Frank Act by

the Companies’ 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 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 disasters 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

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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 cyber 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, 2013, 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, 2013; however, by leaving the indenture open, Virginia Power expects to retain 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.

ENERGY

Dominion Energy’s Cove Point LNG facility has an operational peak regasification daily send-out capacity of approximately 1.8 bcf and an aggregate LNG storage capacity of approximately 14.6 bcf. In addition, Cove Point has a liquefier that has the potential to create approximately 0.01 bcf of LNG per day.

The Cove Point Pipeline is a 36-inch diameter underground, interstate natural gas pipeline that extends approximately 88 miles from Cove Point to interconnections with Transcontinental Gas Pipe Line Company, LLC in Fairfax County, Virginia, and with Columbia Gas Transmission LLC and DTI in Loudoun County, Virginia. In 2009, the original pipeline was expanded to include a 36-inch diameter expansion that extends approximately 48 miles parallel to the original pipeline.

Dominion Energy also owns NGL extraction plants capable of processing over 280,000 mcf per day of natural gas. Hastings is the largest plant and is capable of processing over 180,000 mcf per day of natural gas. Hastings can also fractionate over 580,000 gallons per day of NGLs into marketable products, including propane, isobutane, butane, and natural gasoline. NGL operations have storage capacity of 1,226,500 gallons of propane, 109,000 gallons of isobutane, 442,000 gallons of butane, 2,000,000 gallons of natural gasoline, and 1,012,500 gallons of mixed NGLs.

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, 2013, Dominion Generation’s total utility and merchant generating capacity was approximately 23,600 MW.

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The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2013:

VIRGINIA POWER UTILITY GENERATION

Plant	Location	Net Summer Capability (MW)			Percentage Net Summer Capability
Coal
Mt. Storm	Mt. Storm, WV		1,629
Chesterfield	Chester, VA		1,267
Virginia City Hybrid Energy Center	Wise County, VA		600
Chesapeake(1)	Chesapeake, VA		595
Clover	Clover, VA		437	(3)
Yorktown(1)	Yorktown, VA		323
Bremo(2)	Bremo Bluff, VA		227
Mecklenburg	Clarksville, VA		138
Total Coal			5,216			27	%
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		1,676
North Anna	Mineral, VA		1,672	(4)
Total Nuclear			3,348			17
Oil
Yorktown	Yorktown, VA		790
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			2,160			11
Hydro
Bath County	Warm Springs, VA		1,802	(5)
Gaston	Roanoke Rapids, NC		220
Roanoke Rapids	Roanoke Rapids, NC		95
Other	Various		3
Total Hydro			2,120			11
Biomass
Pittsylvania	Hurt, VA		83
Altavista	Altavista, VA		51
Polyester	Hopewell, VA		51
Southhampton	Southampton, VA		51
Total Biomass			236			1
Various
Other	Various		11			—
			17,680
Power Purchase Agreements			1,926			10
Total Utility Generation			19,606			100	%

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

(1) Certain coal-fired units are expected to be retired at Chesapeake by 2015 and at Yorktown as early as 2016 as a result of the issuance of the MATS rule.

(2) Regulatory approvals have been obtained and plant is expected to be converted to gas in 2014.

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

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

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

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DOMINION MERCHANT GENERATION

Plant	Location	Net Summer Capability (MW)			Percentage Net Summer Capability
Nuclear
Millstone	Waterford, CT		2,001	(2)
Total Nuclear			2,001			51	%
Gas
Fairless (CC)	Fairless Hills, PA		1,196
Manchester (CC)	Providence, RI		446
Total Gas			1,642			41
Wind
Fowler Ridge(1)	Benton County, IN		150	(3)
NedPower Mt. Storm(1)	Grant County, WV		132	(4)
Total Wind			282			7
Solar
Indy Solar (AC)	Indianapolis, IN		29
Azalea Solar (AC)	Washington, GA		8
Somers Solar (AC)	Somers, CT		5
Total Solar			42			1
Fuel Cell
Bridgeport Fuel Cell	Bridgeport, CT		15
Total Fuel Cell			15			—
Total Merchant Generation			3,982			100	%

Note: (CC) denotes combined cycle and (AC) denotes alternating current.

(1) Subject to a lien securing the facility’s debt.

(2) Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal and Green Mountain.

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

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

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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.

See Notes 13 and 22 to the Consolidated Financial Statements and Future Issues and Other Matters in Item 7. 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.

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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 (59)	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 (56)	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 (54)	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 (59)	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 (56)	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.
Robert M. Blue (46)	President of Virginia Power from January 2014 to date; Senior Vice President-Law, Public Policy and Environment of Dominion and Virginia Power from January 2011 to December 2013; 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.
Ashwini Sawhney (64)	Vice President, Controller and CAO of Dominion and Virginia Power from January 2014 to date; Vice President-Accounting and Controller (CAO) of Dominion from May 2010 to December 2013; Vice President and Controller (CAO) of Dominion from July 2009 to May 2010; Vice President-Accounting of Virginia Power from April 2006 to December 2013; Vice President and Controller of Dominion from April 2007 to June 2009.
Diane Leopold (47)	President of DTI, East Ohio and Dominion Cove Point, Inc. and Senior Vice President of DRS from January 2014 to date; Senior Vice President of DTI from April 2012 to December 2013; Senior Vice President—Business Development & Generation Construction of Virginia Power from April 2009 to March 2012; Vice President—Fossil and Hydro Merchant Operations of DEI from September 2007 to March 2009.
Mark O. Webb (49)	Vice President, General Counsel and Chief Risk Officer of Dominion and Virginia Power from January 2014 to date; Vice President and General Counsel of Dominion and Virginia Power from January 2013 to December 2013; Deputy General Counsel of DRS from July 2011 to December 2012; Director—Policy & Business Evaluation AES of DRS from May 2009 to June 2011 and Deputy General Counsel of DRS from April 2004 to April 2009.

(1) Any service listed for Virginia Power, DTI, DEI, East Ohio, Dominion Cove Point, Inc. and DRS reflects service at a subsidiary of Dominion.

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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, 2014, there were approximately 135,000 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 2013 and 2012. 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 2013:

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)
10/1/2013-10/31/13		3,839	$	62.51		N/A	19,629,059 shares/$	1.18 billion
11/1/2013-11/30/13		—	$	—		N/A	19,629,059 shares/$	1.18 billion
12/1/2013-12/31/13		—	$	—		N/A	19,629,059 shares/$	1.18 billion
Total		3,839	$	62.51		N/A	19,629,059 shares/$	1.18 billion

(1) In October 2013, 3,839 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)
2013	$	148	$	120	$	195	$	116	$	579
2012		149		120		110		180		559

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Item 6. Selected Financial Data

DOMINION

Year Ended December 31,	2013			2012			2011			2010			2009
(millions, except per share amounts)
Operating revenue	$	13,120		$	12,835		$	13,765		$	14,392		$	14,032
Income from continuing operations, net of tax(1)		1,789			1,427			1,466			3,056			1,301
Loss from discontinued operations, net of tax(1)		(92	)		(1,125	)		(58	)		(248	)		(14	)
Net income attributable to Dominion		1,697			302			1,408			2,808			1,287
Income from continuing operations before loss from discontinued operations per common share-basic		3.09			2.49			2.56			5.19			2.19
Net income attributable to Dominion per common share-basic		2.93			0.53			2.46			4.77			2.17
Income from continuing operations before loss from discontinued operations per common share-diluted		3.09			2.49			2.55			5.18			2.19
Net income attributable to Dominion per common share-diluted		2.93			0.53			2.45			4.76			2.17
Dividends declared per common share		2.25			2.11			1.97			1.83			1.75
Total assets		50,096			46,838			45,614			42,817			42,554
Long-term debt		19,330			16,851			17,394			15,758			15,481

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

2013 results include a $109 million after-tax charge related to Dominion’s restructuring of its producer services business ($76 million) and an impairment of certain natural gas infrastructure assets ($33 million). Also in 2013, Dominion recorded a $92 million after-tax net loss from the discontinued operations of Brayton Point and Kincaid.

2012 results include a $1.1 billion after-tax loss from discontinued operations, including impairment charges, of 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. 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.

VIRGINIA POWER

Year Ended December 31,	2013		2012		2011		2010		2009
(millions)
Operating revenue	$	7,295	$	7,226	$	7,246	$	7,219	$	6,584
Net income		1,138		1,050		822		852		356
Balance available for common stock		1,121		1,034		805		835		339
Total assets		26,961		24,811		23,544		22,262		20,118
Long-term debt		7,974		6,251		6,246		6,702		6,213

2013 results include a $28 million after-tax charge resulting from impacts of the 2013 Biennial Review Order.

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.

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

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

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

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 at facilities in which Dominion has an ownership interest;

Ÿ Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Domin-

ion’s and Virginia Power’s liquidity position and the under- lying 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 Fluctuations in the value of 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 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, transfers of assets to joint ventures or an MLP, and retirements of assets based on asset portfolio reviews;

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

Ÿ The timing and execution of our MLP strategy;

Ÿ Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules 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, the availability of energy efficient devices and the use of distributed generation methods;

Ÿ Additional competition in industries in which Dominion operates, including in electric markets in which Dominion’s merchant generation facilities operate, and competition in the development, construction and ownership of certain 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 Changes in operating, maintenance and construction costs;

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

Ÿ The inability to complete planned construction, conversion or expansion projects at all, or with the outcomes or within the terms and time frames initially anticipated;

Ÿ Adverse outcomes in litigation matters or regulatory proceedings; and

Ÿ The impact of operational hazards and other catastrophic events.

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

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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, legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. 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 for assets that are in service; for assets that have ceased operations, they adjust the carrying amount of the

ARO liability with such changes recognized in income. The Companies accrete the ARO liability to reflect the passage of time.

In 2013, 2012 and 2011, Dominion recognized $86 million, $77 million and $84 million, respectively, of accretion, and expects to recognize $84 million in 2014. In 2013, 2012 and 2011, Virginia Power recognized $38 million, $34 million and $36 million, respectively, of accretion, and expects to recognize $39 million in 2014. 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, 2013, Dominion’s nuclear decommissioning AROs totaled $1.4 billion, representing approximately 86% of its total AROs. At December 31, 2013, Virginia Power’s nuclear decommissioning AROs totaled $616 million, representing approximately 89% 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 critical assumptions.

In December 2013, Dominion and Virginia Power recorded a reduction of $129 million ($47 million of which was credited to income) and $52 million, respectively, in the nuclear decommissiong AROs for their units due to a reduction in estimated costs.

In September 2012, Dominion recorded an increase of $246 million in the nuclear decommissioning AROs for its units ($183 million of which was charged to income). 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.

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.

37

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

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, 2013, Dominion had $222 million and Virginia Power had $39 million of unrecognized tax benefits. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations.

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, 2013, Dominion had established $69 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, currency exchange 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, 2013, 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 2013, 2012 and 2011 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. 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 selection of an appropriate discount rate. Although cash flow estimates are based on relevant information available at the time

38

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 Forecasts of an independent investment advisor;

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 2013, 2012 and 2011. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 7.75% for 2013, 2012 and 2011. 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 ranged from 4.40% to 4.80% in 2013, and were 5.50% in 2012 and 5.90% in 2011. Dominion selected discount rates ranging from 5.20% to 5.30%, and from 5.00% to 5.10%, for determining its December 31, 2013 projected pension, and other postretirement benefit obligations, respectively.

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, 2013 was 7.00% and is expected to gradually decrease to 4.60% by 2062 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	)%	$	14	$	1
Long-term rate of return on plan assets		(0.25	)%		14		3
Healthcare cost trend rate		1	%		N/A		16

In addition to the effects on cost, at December 31, 2013, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $181 million and its accumulated postretirement benefit obligation by $37 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $140 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

39

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

unbilled revenue. This estimate is reversed in the following month and actual revenue is recorded based on meter readings. Virginia Power’s customer receivables included $395 million and $348 million of accrued unbilled revenue at December 31, 2013 and 2012, 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,	2013		$ Change		2012		$ Change			2011
(millions, except EPS)
Net Income attributable to Dominion	$	1,697	$	1,395	$	302	$	(1,106	)	$	1,408
Diluted EPS		2.93		2.40		0.53		(1.92	)		2.45

Overview

2013 VS. 2012

Net income attributable to Dominion increased by $1.4 billion primarily due to the absence of impairment and other charges recorded in 2012 related to the discontinued operations of Brayton Point and Kincaid and management’s decision to cease operations and begin decommissioning Kewaunee in 2013.

2012 VS. 2011

Net income attributable to Dominion decreased by 79%. Unfavorable drivers include impairment and other charges related to the discontinued operations of 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.

Analysis of Consolidated Operations

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

Year Ended December 31,	2013			$ Change			2012			$ Change			2011
(millions)
Operating Revenue	$	13,120		$	285		$	12,835		$	(930	)	$	13,765
Electric fuel and other energy-related purchases		3,885			240			3,645			(297	)		3,942
Purchased electric capacity		358			(29	)		387			(67	)		454
Purchased gas		1,331			154			1,177			(587	)		1,764
Net Revenue		7,546			(80	)		7,626			21			7,605
Other operations and maintenance		2,459			(632	)		3,091			(87	)		3,178
Depreciation, depletion and amortization		1,208			81			1,127			109			1,018
Other taxes		563			13			550			21			529
Other income		265			42			223			45			178
Interest and related charges		877			61			816			20			796
Income tax expense		892			81			811			33			778
Loss from discontinued operations		(92	)		1,033			(1,125	)		(1,067	)		(58	)

An analysis of Dominion’s results of operations follows:

2013 VS. 2012

Net Revenue decreased 1%, primarily reflecting:

Ÿ A $162 million decrease in producer services primarily related to unfavorable price changes on economic hedging positions, partially offset by higher physical margins, all associated with natural gas aggregation, marketing and trading activities;

Ÿ A $111 million decrease in retail energy marketing activities primarily due to the impact of lower margins on electric sales due to higher purchased power costs; and

Ÿ A $98 million decrease from merchant generation operations, primarily due to lower generation output ($133 million) largely due to the May 2013 closure of Kewaunee, partially offset by higher realized prices ($35 million).

These decreases were partially offset by:

Ÿ A $161 million increase from electric utility operations, primarily reflecting:

Ÿ An increase in sales to retail customers, primarily due to an increase in heating degree days ($112 million); and

Ÿ An increase from rate adjustment clauses ($92 million); partially offset by

Ÿ A decrease in ancillary revenues received from PJM ($12 million) primarily due to a decrease in net operating reserve credits; and

Ÿ A $144 million increase from regulated natural gas transmission operations primarily related to the Appalachian Gateway Project that was placed into service in September 2012 ($44 million), an increase in gathering and storage services ($38 million), NGL activities primarily related to an increase in extraction and fractionation volumes ($19 million) and the Northeast Expansion Project that was placed into service in November 2012 ($16 million).

40

Other operations and maintenance decreased 20%, primarily reflecting:

Ÿ A $589 million decrease related to Kewaunee largely due to the absence of charges recorded in 2012 following management’s decision to cease operations and begin decommissioning in 2013;

Ÿ A $123 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates;

Ÿ A $54 million decrease in storm damage and service restoration costs primarily due to the absence of damage caused by late June summer storms in 2012;

Ÿ A $42 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 Increased gains from the sales of assets to Blue Racer ($32 million).

These decreases were partially offset by:

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

Ÿ A $46 million increase resulting from impacts of the 2013 Biennial Review Order;

Ÿ A $35 million increase due to the absence of adjustments recorded in 2012 in connection with the 2012 North Carolina rate case;

Ÿ A $34 million increase in PJM operating reserves and reactive service charges; and

Ÿ A $26 million charge related to the expected shutdown of certain coal-fired generating units.

Other Income increased 19%, primarily due to higher realized gains (including investment income) on nuclear decommissioning trust funds ($40 million) and a gain on the sale of Dominion’s 50% equity method investment in Elwood ($35 million), partially offset by a decrease in the equity component of AFUDC ($15 million) and a decrease in earnings from equity method investments ($11 million).

Income tax expense increased 10%, primarily reflecting higher pre-tax income in 2013 ($169 million), partially offset by an increase in renewable energy investment tax credits ($46 million) and a lower effective rate for state income taxes ($45 million).

Loss from discontinued operations primarily reflects the sale of Brayton Point and Kincaid in 2013.

2012 VS. 2011

Net Revenue increased $21 million, primarily reflecting:

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 2011 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.

These increases were partially offset by:

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

Ÿ A $91 million decrease from merchant generation operations, primarily reflecting a decrease in realized prices ($147 million), partially offset by increased generation ($56 million).

Other operations and maintenance decreased 3%, primarily reflecting:

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;

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

Ÿ An $89 million decrease attributable to increased deferrals for construction activities related to regulated operations; and

Ÿ A $72 million decrease due to gains from the sale of assets to Blue Racer.

These decreases were partially offset by:

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

Ÿ A $104 million increase in salaries, wages and benefits.

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.

Loss from discontinued operations primarily reflects losses associated with Brayton Point and Kincaid, which were sold in 2013.

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 expects 80% to 90% of future earnings from its primary operating segments to come from regulated and long-term contracted businesses.

In 2014, Dominion is expected to experience an increase in net income on a per share basis as compared to 2013. Dominion’s anticipated 2014 results reflect the following significant factors:

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

Ÿ Growth in weather-normalized electric utility sales of approximately 1.5% resulting from the recovering economy and rising energy demand;

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

Ÿ Construction and operation of growth projects in electric utility operations and associated rate adjustment clause revenue;

Ÿ Construction and operation of growth projects in gas transmission and distribution; and

Ÿ A lower effective tax rate, driven primarily by renewable energy investment tax credits; partially offset by

Ÿ An increase in depreciation, depletion, and amortization;

Ÿ Higher operating and maintenance expenses;

Ÿ Higher interest expenses driven by new debt issuances; and

Ÿ A decrease due to the decision to exit the nonregulated electric retail energy marketing business.

However, if the proposed Virginia legislation for nuclear and offshore wind facilities is signed into law, Dominion would expect to experience a decrease in net income on a per share basis for 2014 as compared to 2013. See Note 13 to the Consolidated Financial Statements for additional information.

On January 2, 2013, U.S. federal legislation was enacted that provides an extension of the 50% 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 2014 of approximately $300 million.

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,	2013						2012						2011
	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(1)	$	475		$	0.82		$	439		$	0.77		$	416		$	0.72
Dominion Generation(1)		1,031			1.78			1,021			1.78			1,078			1.87
Dominion Energy		643			1.11			551			0.96			521			0.91
Primary operating segments		2,149			3.71			2,011			3.51			2,015			3.50
Corporate and Other		(452	)		(0.78	)		(1,709	)		(2.98	)		(607	)		(1.05	)
Consolidated	$	1,697		$	2.93		$	302		$	0.53		$	1,408		$	2.45

(1) Amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

DVP

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

Year Ended December 31,	2013		% Change			2012		% Change			2011
Electricity delivered (million MWh)		82.4		2	%		80.8		(2	)%		82.3
Degree days:
Cooling		1,645		(8	)		1,787		(6	)		1,899
Heating		3,651		24			2,955		(12	)		3,354
Average electric distribution customer accounts (thousands)(1)		2,475		1			2,455		1			2,438

(1) Thirteen-month average.

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

2013 VS. 2012

	Increase(Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	24		$	0.04
Other		(2	)		—
FERC transmission equity return		30			0.05
Storm damage and service restoration(1)		(20	)		(0.03	)
Depreciation		(7	)		(0.01	)
Other operations and maintenance expense		7			0.01
Other		4			0.01
Share dilution		—			(0.02	)
Change in net income contribution	$	36		$	0.05

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

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
Storm damage and service restoration(1)		14			0.03
Other		(4	)		(0.01	)
Change in net income contribution	$	23		$	0.05

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

Dominion Generation

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

Year Ended December 31,	2013		% Change			2012		% Change			2011
Electricity supplied (million MWh):
Utility		82.8		2	%		80.9		(2	)%		82.3
Merchant(1)		26.6		(5	)		28.0		9			25.8
Degree days (electric utility service area):
Cooling		1,645		(8	)		1,787		(6	)		1,899
Heating		3,651		24			2,955		(12	)		3,354
Average retail energy marketing customer accounts (thousands)(2)		2,119		—			2,129		(1	)		2,152

(1) Excludes 7.6 million, 12.8 million and 17.3 million MWh for 2013, 2012 and 2011, respectively, related to Kewaunee, Brayton Point, Kincaid, State Line, Salem and Dominion’s equity method investment in Elwood.

(2) Thirteen-month average.

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

2013 VS. 2012

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Merchant generation margin	$	(14	)	$	(0.02	)
Regulated electric sales:
Weather		44			0.08
Other		(4	)		(0.01	)
Retail energy marketing operations		(54	)		(0.09	)
Rate adjustment clause equity return		35			0.06
PJM ancillary services		(26	)		(0.05	)
Renewable energy investment tax credits		40			0.07
Outage costs		10			0.02
Other		(21	)		(0.04	)
Share dilution		—			(0.02	)
Change in net income contribution	$	10		$	—

2012 VS. 2011

	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Merchant generation margin	$	(72	)	$	(0.13	)
Regulated electric sales:
Weather		(78	)		(0.13	)
Other		46			0.08
Retail energy marketing operations		35			0.06
Rate adjustment clause equity return		17			0.03
PJM ancillary services		(27	)		(0.05	)
Net capacity expenses		19			0.04
Outage costs		10			0.02
Other		(7	)		(0.01	)
Change in net income contribution	$	(57	)	$	(0.09	)

Dominion Energy

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

Year Ended December 31,	2013		% Change			2012		% Change			2011
Gas distribution throughput (bcf):
Sales		29		12	%		26		(13	)%		30
Transportation		281		8			259		2			253
Heating degree days		5,875		18			4,986		(11	)		5,584
Average gas distribution customer accounts (thousands)(1):
Sales		246		(2	)		251		(2	)		256
Transportation		1,049		—			1,044		—			1,040

(1) Thirteen-month average.

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

2013 VS. 2012

	Increase(Decrease)
	Amount			EPS
(millions, except EPS)
Weather	$	8		$	0.01
Producer services margin(1)		(37	)		(0.06	)
Gas transmission margin(2)		88			0.15
Blue Racer(3)		17			0.03
Assignment of Marcellus acreage		12			0.02
Other		4			0.01
Share dilution		—			(0.01	)
Change in net income contribution	$	92		$	0.15

(1) Excludes charges incurred in 2013 associated with the ongoing exit of natural gas trading and certain energy marketing activities which are reflected in the Corporate and Other segment.

(2) Primarily reflects a full year of the Appalachian Gateway Project in service.

(3) Includes a $15 million increase in gains from the sale of assets.

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.

Corporate and Other

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

Year Ended December 31,	2013			2012			2011
(millions, except EPS amounts)
Specific items attributable to operating segments	$	(184	)	$	(1,467	)	$	(364	)
Specific items attributable to Corporate and Other segment		—			(5	)		29
Total specific items		(184	)		(1,472	)		(335	)
Other corporate operations		(268	)		(237	)		(272	)
Total net expense	$	(452	)	$	(1,709	)	$	(607	)
EPS impact	$	(0.78	)	$	(2.98	)	$	(1.05	)

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 those segments’ performance or allocating resources among the segments. See Note 25 to the Consolidated Financial Statements for discussion of these items in more detail.

43

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

VIRGINIA POWER

RESULTS OF OPERATIONS

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

Year Ended December 31,	2013		$ Change		2012		$ Change		2011
(millions)
Net Income	$	1,138	$	88	$	1,050	$	228	$	822

Overview

2013 VS. 2012

Net income increased by 8% primarily due to an increase in rate adjustment clause revenue, the impact of more favorable weather on utility operations, and the absence of restoration costs associated with damage caused by late June 2012 summer storms.

2012 VS. 2011

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

Analysis of Consolidated Operations

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

Year Ended December 31,	2013		$ Change			2012		$ Change			2011
(millions)
Operating Revenue	$	7,295	$	69		$	7,226	$	(20	)	$	7,246
Electric fuel and other energy-related purchases		2,304		(64	)		2,368		(138	)		2,506
Purchased electric capacity		358		(28	)		386		(66	)		452
Net Revenue		4,633		161			4,472		184			4,288
Other operations and maintenance		1,451		(15	)		1,466		(277	)		1,743
Depreciation and amortization		853		71			782		64			718
Other taxes		249		17			232		10			222
Other income		86		(10	)		96		8			88
Interest and related charges		369		(16	)		385		54			331
Income tax expense		659		6			653		113			540

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

2013 VS. 2012

Net Revenue increased 4%, primarily reflecting:

Ÿ An increase in sales to retail customers, primarily due to an increase in heating degree days ($112 million); and

Ÿ An increase from rate adjustment clauses ($92 million); partially offset by

Ÿ A decrease in ancillary revenues received from PJM ($12 million) primarily due to a decrease in net operating reserve credits.

Other operations and maintenance decreased 1%, primarily reflecting:

Ÿ A $123 million decrease in certain electric transmission-related expenditures. These expenses are recovered through FERC rates; and

Ÿ A $54 million decrease in storm damage and service restoration costs primarily due to the absence of damage caused by late June summer storms in 2012.

These decreases were partially offset by:

Ÿ A $46 million increase resulting from impacts of the 2013 Biennial Review Order;

Ÿ A $35 million increase due to the absence of adjustments recorded in 2012 in connection with the 2012 North Carolina rate case;

Ÿ A $34 million increase in PJM operating reserves and reactive service charges;

Ÿ A $26 million charge related to the expected shutdown of certain coal-fired generating units; and

Ÿ A $22 million increase in salaries, wages and benefits.

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 2011 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 2011 Biennial Review Order.

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

Outlook

Virginia Power expects to provide growth in net income in 2014. Virginia Power’s anticipated 2014 results reflect the following significant factors:

Ÿ A return to normal weather;

Ÿ Growth in weather-normalized electric sales of approximately

44

1.5% 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 An increase in depreciation and amortization;

Ÿ Higher operations and maintenance expenses; and

Ÿ Higher interest expenses driven by new debt issuances.

However, if the proposed Virginia legislation for nuclear and offshore wind facilities is signed into law, Virginia Power would expect to experience a decrease in net income for 2014 as compared to 2013. See Note 13 to the Consolidated Financial Statements for additional information.

On January 2, 2013, U.S. federal legislation was enacted that provides an extension of the 50% bonus depreciation allowance for qualifying capital expenditures incurred through 2013, as discussed in Note 5 to the Consolidated Financial Statements. Virginia Power expects the bonus depreciation provisions to reduce income taxes otherwise payable, resulting in cash savings in 2014 of approximately $285 million.

SEGMENT RESULTS OF OPERATIONS

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

Year Ended December 31,	2013			$ Change		2012			$ Change			2011
(millions)
DVP	$	483		$	35	$	448		$	22		$	426
Dominion Generation		702			49		653			(11	)		664
Primary operating segments		1,185			84		1,101			11			1,090
Corporate and Other		(47	)		4		(51	)		217			(268	)
Consolidated	$	1,138		$	88	$	1,050		$	228		$	822

DVP

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

Year Ended December 31,	2013		% Change			2012		% Change			2011
Electricity delivered (million MWh)		82.4		2	%		80.8		(2	)%		82.3
Degree days (electric service area):
Cooling		1,645		(8	)		1,787		(6	)		1,899
Heating		3,651		24			2,955		(12	)		3,354
Average electric distribution customer accounts (thousands)(1)		2,475		1			2,455		1			2,438

(1) Thirteen-month average.

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

2013 VS. 2012

	Increase (Decrease)
(millions, except EPS)
Regulated electric sales:
Weather	$	24
Other		(2	)
FERC transmission equity return		30
Storm damage and service restoration(1)		(20	)
Depreciation		(7	)
Other operations and maintenance expense		7
Other		3
Change in net income contribution	$	35

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

2012 VS. 2011

	Increase (Decrease)
(millions)
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.

Dominion Generation

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

Year Ended December 31,	2013		% Change			2012		% Change			2011
Electricity supplied (million MWh)		82.8		2	%		80.9		(2	)%		82.3
Degree days (electric service area):
Cooling		1,645		(8	)		1,787		(6	)		1,899
Heating		3,651		24			2,955		(12	)		3,354

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

2013 VS. 2012

	Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	44
Other		(4	)
Rate adjustment clause equity return		35
PJM ancillary services		(26	)
Outage costs		15
Other		(15	)
Change in net income contribution	$	49

45

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

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	)

Corporate and Other

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

Year Ended December 31,	2013			2012			2011
(millions)
Specific items attributable to operating segments	$	(47	)	$	(51	)	$	(268	)
Other corporate operations		—			—			—
Total net expense	$	(47	)	$	(51	)	$	(268	)

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, 2012	$	78
Contracts realized or otherwise settled during the period		(64	)
Change in unrealized gains and losses		(100	)
Net unrealized loss at December 31, 2013	$	(86	)

The balance of net unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes at December 31, 2013, 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	2014			2015—2016			2017—2018			2019 and thereafter		Total
(millions)
Prices actively quoted—Level 1(1)	$	—		$	—		$	—		$	—	$	—
Prices provided by other external sources—Level 2(2)		(41	)		(23	)		—			—		(64	)
Prices based on models and other valuation methods—Level 3(3)		(7	)		(10	)		(5	)		—		(22	)
Total	$	(48	)	$	(33	)	$	(5	)	$	—	$	(86	)

(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, 2013, Dominion had $1.6 billion of unused capacity under its credit facilities, including $407 million of unused capacity under joint credit facilities available to Virginia Power. See additional discussion below under Credit Facilities and Short-Term Debt.

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

Year Ended December 31,	2013			2012			2011
(millions)
Cash and cash equivalents at beginning of year	$	248		$	102		$	62
Cash flows provided by (used in):
Operating activities		3,433			4,137			2,983
Investing activities		(3,458	)		(3,840	)		(3,321	)
Financing activities		93			(151	)		378
Net increase in cash and cash equivalents		68			146			40
Cash and cash equivalents at end of year	$	316		$	248		$	102

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

Year Ended December 31,	2013			2012			2011
(millions)
Cash and cash equivalents at beginning of year	$	28		$	29		$	5
Cash flows provided by (used in):
Operating activities		2,329			2,706			2,024
Investing activities		(2,601	)		(2,282	)		(1,947	)
Financing activities		260			(425	)		(53	)
Net increase (decrease) in cash and cash equivalents		(12	)		(1	)		24
Cash and cash equivalents at end of year	$	16		$	28		$	29

Operating Cash Flows

In 2013, net cash provided by Dominion’s operating activities decreased by $704 million, primarily due to lower deferred fuel cost recoveries in its Virginia jurisdiction, higher net margin collateral requirements, and lower margins from retail energy marketing activities and merchant generation operations. The decrease was partially offset by lower rate refund payments and higher margins from regulated natural gas transmission operations.

In 2013, net cash provided by Virginia Power’s operating activities decreased by $377 million, primarily due to lower deferred fuel cost recoveries in its Virginia jurisdiction, higher income tax payments and net changes in other working capital items; partially offset by lower rate refund payments and the impact of 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 2013, Dominion’s Board of Directors affirmed the dividend policy it set in December 2012 for a target payout ratio of 65-70%, and established an annual dividend rate for 2014 of $2.40 per share of common stock, a 6.7% increase over the 2013 rate. In January 2014, Dominion’s Board of Directors declared dividends payable March 20, 2014 of 60 cents per share of common stock. 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, 2013 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)	$	100	$	—	$	100
Non-investment grade(2)		4		—		4
No external ratings:
Internally rated-investment grade(3)		67		—		67
Internally rated-non-investment grade(4)		92		—		92
Total	$	263	$	—	$	263

(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 20% 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 15% of the total net credit exposure.

(4) The five largest counterparty exposures, combined, for this category represented approximately 14% 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, 2013.

Investing Cash Flows

In 2013, net cash used in Dominion’s investing activities decreased by $382 million, primarily due to the proceeds from the sale of Brayton Point, Kincaid and equity method investment in Elwood and lower restricted cash reimbursements for the purpose of funding certain qualifying construction projects.

In 2013, net cash used in Virginia Power’s investing activities increased by $319 million, primarily due to higher capital expenditures.

Financing Cash Flows and Liquidity

Dominion and Virginia Power rely on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by their operations. As discussed 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 registration statements to register any offering of securities, other than those for exchange offers or business combination transactions.

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

In 2013, net cash provided by Dominion’s financing activities was $93 million as compared to net cash used in financing activities of $151 million in 2012, primarily reflecting higher net debt issuances, partially offset by the acquisition of the Juniper noncontrolling interest in Fairless and higher common dividend payments. See Note 15 to the Consolidated Financial Statements for more information.

In 2013, net cash provided by Virginia Power’s financing activities was $260 million compared to net cash used in financing activities of $425 million in 2012, primarily reflecting higher net debt issuances.

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, 2013	Facility Limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility(1)	$	3,000	$	1,927		$	—	$	1,073
Joint revolving credit facility(2)		500		—			11		489
Total	$	3,500	$	1,927	(3)	$	11	$	1,562

(1) Effective September 2013, the maturity date was extended from September 2017 to September 2018. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.

(2) Effective September 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

(3) The weighted-average interest rate of the outstanding commercial paper supported by Dominion’s credit facilities was 0.33% at December 31, 2013.

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, 2013	Facility Sub-limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Sub-limit Capacity Available
(millions)
Joint revolving credit facility(1)	$	1,000	$	842		$	—	$	158
Joint revolving credit facility(2)		250		—			1		249
Total	$	1,250	$	842	(3)	$	1	$	407

(1) Effective September 2013, the maturity date was extended from September 2017 to September 2018. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.

(2) Effective September 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s 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 0.33% at December 31, 2013.

In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility. Effective September 2013, the maturity date was extended from September 2017 to September 2018. As of December 31, 2013, this facility supports approximately $119 million of certain variable rate 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 matured and were repaid in November 2013 and bore interest at a variable rate. The proceeds were used for general corporate purposes.

In November 2013, Dominion issued $400 million of private placement short-term notes that mature in November 2014 and bear interest at a variable rate. The proceeds were used for general corporate purposes.

48

LONG-TERM DEBT

During 2013, Dominion and Virginia Power issued the following long-term debt:

Type	Principal		Rate			Maturity		Issuing Company
	(millions)
Remarketable subordinated notes	$	550		1.18	%		2019		Dominion
Remarketable subordinated notes		550		1.07	%		2021		Dominion
Senior notes		250		1.20	%		2018		Virginia Power
Senior notes		500		2.75	%		2023		Virginia Power
Senior notes		500		4.00	%		2043		Virginia Power
Senior notes		585		4.65	%		2043		Virginia Power
Total notes issued	$	2,935

In March 2013, Virginia Power redeemed the $50 million 2.5% IDA of the Town of Louisa, Virginia Solid Waste and Sewage Disposal Revenue Bonds, Series 2001A, that would have otherwise matured in March 2031. In February 2014, Virginia Power provided notice to redeem the $10 million 2.5% and the $30 million 2.5% IDA of the Town of Louisa, Virginia Solid Waste and Sewage Disposal Revenue Bonds, Series 1997A and 2000A, that would otherwise mature in April 2022 and September 2030, respectively. The bonds will be redeemed on April 1, 2014 at the amount of principal then outstanding plus accrued interest. At December 31, 2013, the bonds were included in securities due within one year in Virginia Power’s Consolidated Balance Sheets.

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

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

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

Dominion Gas issued $1.2 billion principal amount of unsecured senior notes in a private placement in October 2013 and will be the primary financing entity for Dominion’s regulated natural gas businesses. Dominion Gas used the proceeds from this offering to acquire intercompany long-term notes from Dominion and to repay a portion of its intercompany revolving credit agreement balances with Dominion.

During 2013, Dominion and Virginia Power repaid and repurchased $1.5 billion and $470 million, respectively, of long-term debt and notes payable.

ISSUANCE OF COMMON STOCK AND OTHER EQUITY SECURITIES

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. In January 2014, Dominion began purchasing its common stock on the open market for these plans.

During 2013, Dominion issued approximately 5.4 million shares of common stock through various programs. Dominion received cash proceeds of $279 million from the issuance of 4.7 million of such shares through Dominion Direct and employee savings plans.

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 $317 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 2013.

In June 2013, Dominion issued equity units, initially in the form of Corporate Units. Each Corporate Unit consists of a stock purchase contract and 1/20 interest in a RSN issued by Dominion. The stock purchase contracts obligate the holders to purchase shares of Dominion common stock at a future settlement date. See Note 17 to the Consolidated Financial Statements for a description of common stock to be issued by Dominion.

In 2013, Virginia Power did not issue any shares of its common stock to Dominion.

REPURCHASE OF COMMON STOCK

Dominion did not repurchase any shares in 2013 and does not plan to repurchase shares during 2014, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock and purchases of common stock on the open market in 2014 for direct stock purchase plans, 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 $97 million at December 31, 2013. There were no long-term borrowings from Dominion at December 31, 2013. At December 31, 2013, Virginia Power’s nonregulated subsidiaries had no borrowings under the Dominion money pool.

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

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

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. The Companies’ credit ratings 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.

In October 2013, Standard & Poor’s affirmed Dominion’s corporate credit rating of A- but lowered the rating for Dominion’s senior unsecured debt securities to BBB+ from A- to reflect greater structural subordination at Dominion due to new debt at Dominion Gas. Dominion cannot predict with certainty the potential impact the lowered rating could have on its cost of borrowing.

Credit ratings as of February 24, 2014 follow:

	Fitch		Moody’s		Standard & Poor’s
Dominion
Senior unsecured debt securities		BBB+		Baa2		BBB+
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		Aa3		A
Senior unsecured (including tax-exempt) debt securities		A-		A2		A-
Junior subordinated debt securities		BBB		A3		BBB
Preferred stock		BBB		Baa1		BBB
Commercial paper		F2		P-1		A-2

As of February 24, 2014, 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 could result in an increase in 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 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, 2013, 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	%		58	%
Virginia Power		65	%		47	%

(1) Indebtedness as defined by the bank agreements excludes junior subordinated and remarketable subordinated notes reflected as long-term debt 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.

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At December 31, 2013, 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, 2013, 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, 2013; 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, 2013, 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, 2013.

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 and equity units, initially in the form of corporate units, 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, 2013. 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 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 2014.

Dominion	2014		2015- 2016		2017- 2018		2019 and thereafter		Total
(millions)
Long-term debt(1)	$	1,505	$	2,731	$	2,728	$	13,878	$	20,842
Interest payments(2)		1,006		1,855		1,593		13,280		17,734
Leases(3)		63		111		80		87		341
Purchase obligations(4):
Purchased electric capacity for utility operations		336		569		263		163		1,331
Fuel commitments for utility operations		776		831		238		323		2,168
Fuel commitments for nonregulated operations		68		143		183		168		562
Pipeline transportation and storage		97		113		75		240		525
Energy commodity purchases for resale(5)		307		45		29		190		571
Other(6)		1,495		1,686		90		15		3,286
Other long-term liabilities(7):
Financial derivative-commodities(5)		126		24		2		—		152
Other contractual obligations(8)		64		95		2		—		161
Total cash payments	$	5,843	$	8,203	$	5,283	$	28,344	$	47,673

(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 and payments on related stock purchase contracts. Interest is calculated using the applicable interest rate or forward interest rate curve at December 31, 2013 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 and stock purchase contract payments on junior subordinated notes or RSNs and equity units, initially in the form of Corporate Units.

(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,

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

$160 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	2014		2015- 2016		2017- 2018		2019 and thereafter		Total
(millions)
Long-term debt(1)	$	58	$	687	$	1,529	$	5,769	$	8,043
Interest payments(2)		386		744		671		4,857		6,658
Leases(3)		27		47		31		27		132
Purchase obligations(4):
Purchased electric capacity for utility operations		336		569		263		163		1,331
Fuel commitments for utility operations		776		831		238		323		2,168
Transportation and storage		34		59		50		222		365
Other(5)		353		26		4		10		393
Total cash payments(6)	$	1,970	$	2,963	$	2,786	$	11,371	$	19,090

(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, 2013 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, $28 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 $5.6 billion, $4.6 billion and $4.2 billion in 2014, 2015 and 2016, respectively. Dominion’s expenditures are expected to include construction and expansion of electric generation and natural gas transmission, distribution and storage facilities, construction improvements and expansion of electric transmission and distribution assets, purchases of nuclear fuel and the planned construction of the Cove Point liquefaction project in Maryland.

Virginia Power’s planned capital expenditures are expected to total approximately $3.0 billion, $2.5 billion and $2.3 billion in 2014, 2015 and 2016, 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 2013 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 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 $182 million, $189 million and $184 million of expenses (including depreciation) during 2013, 2012, and 2011 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $174 million and $182 million in 2014 and 2015, respectively. In addition, capital expenditures related to environmental controls were $64 million, $213 million, and $403 million for 2013, 2012 and 2011, respectively. These expenditures are expected to be approximately $107 million and $83 million for 2014 and 2015, respectively.

Virginia Power incurred approximately $150 million, $120 million and $129 million of expenses (including depreciation) during 2013, 2012 and 2011, respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $146 million and $155 million in 2014 and 2015, respectively. In addition, capital

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expenditures related to environmental controls were $44 million, $34 million and $77 million for 2013, 2012 and 2011, respectively. These expenditures are expected to be approximately $89 million and $71 million for 2014 and 2015, 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, delegated 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 have also been 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 applicable 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 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. The EPA has delayed the final rule on five separate occasions and has most recently announced that a final rule will be issued no later than April 2014.

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 Companies’ results of operations, financial condition and/or cash flows.

In June 2013, the EPA issued a proposed rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The proposed rule establishes updated standards for wastewater discharges at coal, oil, gas, and nuclear steam generating stations. Affected facilities could be required to convert from wet to dry coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. The EPA is subject to a consent decree requiring that it take final action on the proposed rule by May 22, 2014. Dominion and Virginia Power currently cannot predict with certainty the direct or indirect financial impact on operations from these rule

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

revisions, but believes the expenditures to comply with any new requirements could be material.

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

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 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.

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, including rules regarding margin requirements for non-cleared swaps. 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 swaps provisions of the Dodd-Frank Act by the Companies’ 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

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 is expected to cost between approximately $3.4 billion and $3.8 billion, exclusive of financing costs. Subject to environmental review by FERC and final FERC and Maryland Commission approval, the Cove Point facility is authorized to export at a rate of 770 million cubic feet of natural gas per day for a period of 20 years. 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. In September 2013, the DOE conditionally authorized Dominion to export LNG from Cove Point to non-free trade agreement countries.

In April 2013, Cove Point filed with FERC for permission to build liquefaction and other facilities related to the export of natural gas. Also in April 2013, Cove Point filed an application with the Maryland Commission for a CPCN to authorize the construction of an electric generating station needed to power the proposed liquefaction equipment.

In April 2013, Dominion announced it had fully subscribed the capacity of the project with signed 20-year terminal service agreements. Pacific Summit Energy, LLC, a U.S. affiliate of Japanese trading company Sumitomo Corporation, and GAIL Global (USA) LNG LLC, a U.S. affiliate of GAIL (India) Ltd., have each contracted for half of the capacity. Dominion also announced it had awarded its engineering, procurement and construction contract for new liquefaction facilities to IHI/Kiewit Cove Point, a joint venture between IHI E&C International Corporation and Kiewit Energy Company, following completion of the front-end engineering and design work. Following receipt of regulatory and other approvals, construction of liquefaction facilities could begin in 2014 with an in-service date in late 2017.

Cove Point has historically operated as an LNG import facility, under various long-term import contracts. Since 2010, Dominion has renegotiated certain existing LNG import contracts in a manner that will result in a significant reduction in pipeline and storage capacity utilization and associated anticipated revenues during the period from 2017 through 2028. Such amendments created the opportunity for Dominion to explore the Cove Point liquefaction project, which, assuming it becomes operational, will extend the economic life of Cove Point and contribute to Dominion’s overall growth plan. In total, these renegotiations reduced expected annual revenues from the import-related contracts by approximately $150 million annually from 2017 through 2028, partially offset by approximately $50 million of additional revenues in the years 2013 through 2017.

Dominion is party to an agreement with the Sierra Club restricting activities on portions of the Cove Point property. In May 2012, in response to claims by the Sierra Club, Cove Point filed a complaint for declaratory judgment to confirm its right to

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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. In March 2013, Cove Point filed a petition with the Maryland Court of Appeals, the highest appellate court in Maryland, requesting that the Court of Appeals take the appeal directly thus bypassing the intermediate appellate court. In April 2013, the Maryland Court of Appeals denied the petition, and the appeal remains with the Maryland Court of Special Appeals. In January 2014, oral arguments were held in the Maryland Court of Special Appeals. This case is pending. Dominion believes that the agreement with the Sierra Club permits it to locate, construct and operate a liquefaction plant at the Cove Point facility.

Undergrounding Legislation

Legislation has been proposed which would provide for the recovery of costs, subject to approval by the Virginia Commission, for Virginia Power to move approximately 4,000 miles of electric distribution lines underground. The program, designed to reduce restoration outage time, has an annual investment cap of approximately $175 million and is expected to be implemented over the next decade.

Electric Transmission System Security Plan

Over the next 5 to 10 years, Virginia Power plans to increase transmission substation physical security and to invest in a new system operations center. Virginia Power expects to invest $300 million - $500 million during that time to strengthen its electrical system to better protect critical equipment, enhance its spare equipment process, and create multiple levels of security.

Solar Facilities

Dominion plans to expand its fleet of contracted solar facilities over the next 24 months by approximately 250 MW. Dominion is currently in active discussions with multiple parties for facilities expected to be placed into service in 2014 and 2015.

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 and Dominion’s gas procurement 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. In the second quarter of 2013, Dominion commenced a restructuring of its producer services business, which will result in the termination of natural gas trading and certain energy marketing activities. This, combined with Dominion’s decision in January 2014 to exit the electric retail energy marketing business, will reduce Dominion’s commodity price risk exposure.

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 an increase in fair value of approximately $171 million and $126 million as of December 31, 2013 and 2012, respectively. A hypothetical 10% unfavorable change in commodity prices of Dominion’s commodity-based financial derivative instruments held for trading purposes would have resulted in a decrease in fair value of approximately $17 million and $18 million as of December 31, 2013 and 2012, respectively.

A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of Virginia Power’s non-trading commodity-based financial derivatives as of December 31, 2013 or 2012.

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

Interest Rate Risk

Dominion and Virginia Power manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock

55

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

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, 2013 or 2012.

Dominion and Virginia Power may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. As of December 31, 2013, Dominion and Virginia Power had $1.1 billion and $600 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $20 million and $13 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at December 31, 2013. As of December 31, 2012, Dominion and Virginia Power had $1.8 billion and $750 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $21 million and $9 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at December 31, 2012.

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

Investment Price Risk

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

Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $163 million and $126 million in 2013 and 2012, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2013 and 2012, Dominion recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $417 million and $210 million, respectively.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $52 million and $53 million in 2013 and 2012, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2013 and 2012, Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $193 million and $89 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 $959 million in 2013 and $743 million in 2012, versus expected returns of $554 million and $509 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. 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 $14 million and $13 million as of December 31, 2013 and 2012, respectively, for pension benefits and $3 million as of December 31, 2013 and 2012, 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, 2013 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.

56

Item 8. Financial Statements and Supplementary Data

	Page No.
Dominion Resources, Inc.
Report of Independent Registered Public Accounting Firm		58
Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011		59
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011		60
Consolidated Balance Sheets at December 31, 2013 and 2012		61
Consolidated Statements of Equity at December 31, 2013, 2012 and 2011 and for the years then ended		63
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011		64
Virginia Electric and Power Company
Report of Independent Registered Public Accounting Firm		65
Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011		66
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011		67
Consolidated Balance Sheets at December 31, 2013 and 2012		68
Consolidated Statements of Common Shareholder’s Equity at December  31, 2013, 2012 and 2011 and for the years then ended		70
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011		71
Combined Notes to Consolidated Financial Statements		72

57

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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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 (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2014 expressed an unqualified opinion on Dominion’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2014

58

Dominion Resources, Inc.

Consolidated Statements of Income

Year Ended December 31,	2013			2012(1)			2011(1)
(millions, except per share amounts)
Operating Revenue	$	13,120		$	12,835		$	13,765
Operating Expenses
Electric fuel and other energy-related purchases		3,885			3,645			3,942
Purchased electric capacity		358			387			454
Purchased gas		1,331			1,177			1,764
Other operations and maintenance		2,459			3,091			3,178
Depreciation, depletion and amortization		1,208			1,127			1,018
Other taxes		563			550			529
Total operating expenses		9,804			9,977			10,885
Income from operations		3,316			2,858			2,880
Other income		265			223			178
Interest and related charges		877			816			796
Income from continuing operations including noncontrolling interests before income taxes		2,704			2,265			2,262
Income tax expense		892			811			778
Income from continuing operations including noncontrolling interests		1,812			1,454			1,484
Loss from discontinued operations(2)		(92	)		(1,125	)		(58	)
Net income including noncontrolling interests		1,720			329			1,426
Noncontrolling interests		23			27			18
Net income attributable to Dominion		1,697			302			1,408
Amounts attributable to Dominion:
Income from continuing operations, net of tax		1,789			1,427			1,466
Loss from discontinued operations, net of tax		(92	)		(1,125	)		(58	)
Net income attributable to Dominion		1,697			302			1,408
Earnings Per Common Share-Basic:
Income from continuing operations	$	3.09		$	2.49		$	2.56
Loss from discontinued operations		(0.16	)		(1.96	)		(0.10	)
Net income attributable to Dominion	$	2.93		$	0.53		$	2.46
Earnings Per Common Share-Diluted:
Income from continuing operations	$	3.09		$	2.49		$	2.55
Loss from discontinued operations		(0.16	)		(1.96	)		(0.10	)
Net income attributable to Dominion	$	2.93		$	0.53		$	2.45
Dividends declared per common share	$	2.25		$	2.11		$	1.97

(1) Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

(2) Includes income tax benefit of $43 million, $692 million, and $33 million in 2013, 2012 and 2011, respectively. For 2012, includes impairment charges of $1.6 billion related to Brayton Point and Kincaid. See Note 6 for additional information.

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

59

Dominion Resources, Inc.

Consolidated Statements of Comprehensive Income

Year Ended December 31,	2013			2012			2011
(millions)
Net income including noncontrolling interests	$	1,720		$	329		$	1,426
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $161, $5 and $48 tax		(243	)		(8	)		(67	)
Changes in unrealized net gains on investment securities, net of $(136), $(68) and $(7) tax		203			108			11
Changes in net unrecognized pension and other postretirement benefit costs, net of $(341), $209 and $147 tax		516			(330	)		(231	)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of $(53), $34 and $28 tax		77			(60	)		(38	)
Net realized (gains) losses on investment securities, net of $35, $16 and $(4) tax		(55	)		(25	)		6
Net pension and other postretirement benefit costs, net of $(39), $(32) and $(25) tax		55			48			39
Total other comprehensive income (loss)		553			(267	)		(280	)
Comprehensive income including noncontrolling interests		2,273			62			1,146
Comprehensive income attributable to noncontrolling interests		23			27			18
Comprehensive income attributable to Dominion	$	2,250		$	35		$	1,128

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

60

Dominion Resources, Inc.

Consolidated Balance Sheets

At December 31,	2013			2012
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	316		$	248
Customer receivables (less allowance for doubtful accounts of $25 and $28)		1,695			1,621
Other receivables (less allowance for doubtful accounts of $4 at both dates)		141			96
Inventories:
Materials and supplies		689			684
Fossil fuel		393			467
Gas stored		94			108
Derivative assets		687			518
Margin deposit assets		620			212
Prepayments		192			326
Deferred income taxes		778			573
Other		335			287
Total current assets		5,940			5,140
Investments
Nuclear decommissioning trust funds		3,903			3,330
Investment in equity method affiliates		916			558
Other		283			303
Total investments		5,102			4,191
Property, Plant and Equipment
Property, plant and equipment		46,969			43,364
Property, plant and equipment, VIE		—			957
Accumulated depreciation, depletion and amortization		(14,341	)		(13,548	)
Total property, plant and equipment, net		32,628			30,773
Deferred Charges and Other Assets
Goodwill		3,086			3,130
Pension and other postretirement benefit assets		942			702
Intangible assets, net		560			536
Regulatory assets		1,228			1,717
Other		610			649
Total deferred charges and other assets		6,426			6,734
Total assets	$	50,096		$	46,838

61

At December 31,	2013			2012
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	1,519		$	1,363
Securities due within one year, VIE		—			860
Short-term debt		1,927			2,412
Accounts payable		1,168			1,137
Accrued interest, payroll and taxes		609			636
Derivative liabilities		828			510
Other		943			845
Total current liabilities		6,994			7,763
Long-Term Debt
Long-term debt		16,877			15,478
Junior subordinated notes		1,373			1,373
Remarketable subordinated notes		1,080			—
Total long-term debt		19,330			16,851
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		7,114			5,800
Asset retirement obligations		1,484			1,641
Pension and other postretirement benefit liabilities		481			1,831
Regulatory liabilities		2,001			1,514
Other		793			556
Total deferred credits and other liabilities		11,873			11,342
Total liabilities		38,197			35,956
Commitments and Contingencies (see Note 22)
Subsidiary Preferred Stock Not Subject To Mandatory Redemption		257			257
Equity
Common stock-no par(1)		5,783			5,493
Other paid-in capital		—			162
Retained earnings		6,183			5,790
Accumulated other comprehensive loss		(324	)		(877	)
Total common shareholders’ equity		11,642			10,568
Noncontrolling interest		—			57
Total equity		11,642			10,625
Total liabilities and equity	$	50,096		$	46,838

(1) 1 billion shares authorized; 581 million shares and 576 million shares outstanding at December 31, 2013 and 2012, respectively.

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

62

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, 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 loss, net of tax														(267	)		(267	)					(267	)
December 31, 2012		576			5,493			162			5,790			(877	)		10,568			57			10,625
Net income including noncontrolling interests											1,714						1,714			6			1,720
Issuance of stock-employee and direct stock purchase plans		4			278												278						278
Stock awards (net of change in unearned compensation)					12												12						12
Other stock issuances(4)		1			15			(8	)								7						7
Present value of stock purchase contract payments related to RSNs(5)								(154	)		(2	)					(156	)					(156	)
Fairless lease buyout(6)					(15	)											(15	)		(57	)		(72	)
Dividends											(1,319	)(1)					(1,319	)		(6	)		(1,325	)
Other comprehensive income, net of tax														553			553						553
December 31, 2013		581		$	5,783		$	—		$	6,183		$	(324	)	$	11,642		$	—		$	11,642

(1) Includes subsidiary preferred dividends related to noncontrolling interests of $17 million, $16 million and $17 million in 2013, 2012 and 2011, respectively.

(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.

(4) Primarily includes $28 million in shares issued in excess of principal amounts related to converted securities. See Note 17 for further information on convertible securities.

(5) See Note 17 for further information.

(6) See Note 15 for further information.

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

63

Dominion Resources, Inc.

Consolidated Statements of Cash Flows

Year Ended December 31,	2013			2012			2011
(millions)
Operating Activities
Net income including noncontrolling interests	$	1,720		$	329		$	1,426
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Impairment of generation assets		48			2,089			283
Net reserves (payments) related to rate refunds		(5	)		(151	)		3
Depreciation, depletion and amortization (including nuclear fuel)		1,390			1,443			1,288
Deferred income taxes and investment tax credits		737			246			756
Gains on the sale of assets		(122	)		(81	)		—
Other adjustments		(129	)		(164	)		(207	)
Changes in:
Accounts receivable		(98	)		292			365
Inventories		(29	)		33			(185	)
Deferred fuel and purchased gas costs, net		102			368			(3	)
Prepayments		123			(85	)		(19	)
Accounts payable		50			(61	)		(413	)
Accrued interest, payroll and taxes		(27	)		(12	)		(216	)
Margin deposit assets and liabilities		(414	)		45			(71	)
Other operating assets and liabilities		87			(154	)		(24	)
Net cash provided by operating activities		3,433			4,137			2,983
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(4,104	)		(4,145	)		(3,652	)
Proceeds from sales of securities		1,476			1,356			1,757
Purchases of securities		(1,493	)		(1,392	)		(1,824	)
Proceeds from the sale of Brayton Point, Kincaid and equity method investment in Elwood		465			—			—
Proceeds from Blue Racer		160			115			—
Restricted cash equivalents		25			108			259
Other		13			118			139
Net cash used in investing activities		(3,458	)		(3,840	)		(3,321	)
Financing Activities
Issuance (repayment) of short-term debt, net		(485	)		598			429
Issuance of short-term notes		400			400			—
Repayment of short-term notes		(400	)		—			—
Issuance and remarketing of long-term debt		4,135			1,500			2,320
Repayment and repurchase of long-term debt, including redemption premiums		(1,245	)		(1,675	)		(637	)
Repayment of junior subordinated notes		(258	)		—			—
Acquisition of Juniper noncontrolling interest in Fairless		(923	)		—			—
Issuance of common stock		278			265			38
Repurchase of common stock		—			—			(601	)
Common dividend payments		(1,302	)		(1,209	)		(1,129	)
Subsidiary preferred dividend payments		(17	)		(16	)		(17	)
Other		(90	)		(14	)		(25	)
Net cash provided by (used in) financing activities		93			(151	)		378
Increase in cash and cash equivalents		68			146			40
Cash and cash equivalents at beginning of year		248			102			62
Cash and cash equivalents at end of year	$	316		$	248		$	102
Supplemental Cash Flow Information
Cash paid (received) during the year for:
Interest and related charges, excluding capitalized amounts	$	852		$	913		$	920
Income taxes		56			(58	)		166
Significant noncash investing and financing activities:
Accrued capital expenditures		375			388			328
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.

64

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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2014

65

Virginia Electric and Power Company

Consolidated Statements of Income

Year Ended December 31,	2013		2012		2011
(millions)
Operating Revenue	$	7,295	$	7,226	$	7,246
Operating Expenses
Electric fuel and other energy-related purchases		2,304		2,368		2,506
Purchased electric capacity		358		386		452
Other operations and maintenance:
Affiliated suppliers		290		305		306
Other		1,161		1,161		1,437
Depreciation and amortization		853		782		718
Other taxes		249		232		222
Total operating expenses		5,215		5,234		5,641
Income from operations		2,080		1,992		1,605
Other income		86		96		88
Interest and related charges		369		385		331
Income from operations before income tax expense		1,797		1,703		1,362
Income tax expense		659		653		540
Net Income		1,138		1,050		822
Preferred dividends		17		16		17
Balance available for common stock	$	1,121	$	1,034	$	805

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

66

Virginia Electric and Power Company

Consolidated Statements of Comprehensive Income

Year Ended December 31,	2013			2012			2011
(millions)
Net income	$	1,138		$	1,050		$	822
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $(3), $3 and $3 tax		6			(5	)		(6	)
Changes in unrealized net gains on nuclear decommissioning trust funds, net of $(13), $(7) and $(1) tax		20			13			2
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of $—, $(2) and $— tax		—			2			(1	)
Net realized gains on nuclear decommissioning trust funds, net of $2, $2 and $— tax		(3	)		(4	)		—
Other comprehensive income (loss)		23			6			(5	)
Comprehensive income	$	1,161		$	1,056		$	817

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

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Virginia Electric and Power Company

Consolidated Balance Sheets

At December 31,	2013			2012
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	16		$	28
Customer receivables (less allowance for doubtful accounts of $11 and $10)		946			849
Other receivables (less allowance for doubtful accounts of $2 and $3)		78			51
Inventories (average cost method):
Materials and supplies		418			385
Fossil fuel		390			404
Prepayments		32			23
Regulatory assets		128			119
Deferred income taxes		87			92
Other		68			30
Total current assets		2,163			1,981
Investments
Nuclear decommissioning trust funds		1,765			1,515
Other		12			14
Total investments		1,777			1,529
Property, Plant and Equipment
Property, plant and equipment		32,848			30,631
Accumulated depreciation and amortization		(10,580	)		(10,014	)
Total property, plant and equipment, net		22,268			20,617
Deferred Charges and Other Assets
Intangible assets, net		193			181
Regulatory assets		417			396
Other		143			107
Total deferred charges and other assets		753			684
Total assets	$	26,961		$	24,811

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At December 31,	2013		2012
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	58	$	418
Short-term debt		842		992
Accounts payable		479		430
Payables to affiliates		69		67
Affiliated current borrowings		97		435
Accrued interest, payroll and taxes		218		204
Derivative liabilities		12		33
Customer deposits		95		100
Regulatory liabilities		41		32
Other		306		296
Total current liabilities		2,217		3,007
Long-Term Debt		7,974		6,251
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		4,137		3,879
Asset retirement obligations		689		705
Regulatory liabilities		1,597		1,285
Other		292		194
Total deferred credits and other liabilities		6,715		6,063
Total liabilities		16,906		15,321
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		1,113
Retained earnings		2,899		2,357
Accumulated other comprehensive income		48		25
Total common shareholder’s equity		9,798		9,233
Total liabilities and shareholder’s equity	$	26,961	$	24,811

(1) 500,000 shares authorized at December 31, 2013 and 2012; 274,723 shares outstanding at December 31, 2013 and 2012.

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

69

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, 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
Net income								1,138						1,138
Dividends								(596	)					(596	)
Other comprehensive income, net of tax											23			23
Balance at December 31, 2013		275	$	5,738	$	1,113	$	2,899		$	48		$	9,798

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

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Virginia Electric and Power Company

Consolidated Statements of Cash Flows

Year Ended December 31,	2013			2012			2011
(millions)
Operating Activities
Net income	$	1,138		$	1,050		$	822
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		1,016			927			838
Deferred income taxes and investment tax credits, net		240			502			496
Impairment of generation assets		—			—			228
Net reserves (payments) related to rate refunds		(5	)		(151	)		3
Other adjustments		(63	)		(70	)		(93	)
Changes in:
Accounts receivable		(124	)		126			76
Affiliated accounts receivable and payable		3			(2	)		(7	)
Inventories		(19	)		8			(200	)
Deferred fuel expenses, net		93			378			12
Prepayments		(9	)		18			24
Accounts payable		15			19			(117	)
Accrued interest, payroll and taxes		14			(22	)		12
Other operating assets and liabilities		30			(77	)		(70	)
Net cash provided by operating activities		2,329			2,706			2,024
Investing Activities
Plant construction and other property additions		(2,394	)		(2,082	)		(1,885	)
Purchases of nuclear fuel		(139	)		(206	)		(205	)
Purchases of securities		(603	)		(638	)		(1,057	)
Proceeds from sales of securities		572			626			1,030
Restricted cash equivalents		2			22			137
Other		(39	)		(4	)		33
Net cash used in investing activities		(2,601	)		(2,282	)		(1,947	)
Financing Activities
Issuance (repayment) of short-term debt, net		(151	)		98			294
Issuance (repayment) of affiliated current borrowings, net		(338	)		248			85
Issuance and remarketing of long-term debt		1,835			450			235
Repayment and repurchase of long-term debt		(470	)		(641	)		(91	)
Common dividend payments		(579	)		(559	)		(557	)
Preferred dividend payments		(17	)		(16	)		(17	)
Other		(20	)		(5	)		(2	)
Net cash provided by (used in) financing activities		260			(425	)		(53	)
Increase (decrease) in cash and cash equivalents		(12	)		(1	)		24
Cash and cash equivalents at beginning of year		28			29			5
Cash and cash equivalents at end of year	$	16		$	28		$	29
Supplemental Cash Flow Information
Cash paid (received) during the year for:
Interest and related charges, excluding capitalized amounts	$	328		$	376		$	376
Income taxes		427			225			(27	)
Significant noncash investing activities:
Accrued capital expenditures		276			242			199

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

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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, transport 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.

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

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 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 2012 and 2011 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2013 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

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

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, 2013 and 2012 included $555 million and $411 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, 2013 and 2012 included $395 million and $348 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;

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

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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.

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 84% 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. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, 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.

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 2013, Dominion recognized interest income of $3 million and interest expense of $10 million and no penalties. In 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. Dominion had accrued interest receivable of $5 million, interest payable of $15 million and penalties payable of less than $1 million at December 31, 2013 and interest receivable of $5 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2012.

Virginia Power’s interest and penalties were immaterial in 2013 and 2012. In 2011, Virginia Power recognized interest income of $12 million, and penalties were immaterial.

At December 31, 2013, Virginia Power’s Consolidated Balance Sheet included $3 million of state income taxes receivable, $22 million of federal and state income taxes payable, $12 million of noncurrent state income taxes receivable and $28 million of noncurrent federal and state income taxes payable.

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.

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, 2013 and 2012, Dominion’s accounts payable included $38 million and $53 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 2013 and 2012, Virginia Power’s accounts payable included $21 million and $30 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.

73

Combined Notes to Consolidated Financial Statements, Continued

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 $620 million and $212 million associated with cash collateral at December 31, 2013 and 2012, respectively. Dominion had margin liabilities of $2 million and $4 million associated with cash collateral at December 31, 2013 and 2012, respectively. Virginia Power had margin assets of $11 million and $18 million associated with cash collateral at December 31, 2013 and 2012, respectively. Virginia Power’s margin liabilities associated with cash collateral were not material at December 31, 2013 and 2012. See Note 7 for further information about offsetting derivatives.

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 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.

74

Property, Plant and Equipment

Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, 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 generally charged to expense as it is incurred.

In 2013, 2012 and 2011, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $66 million, $91 million and $85 million, respectively. In 2013, 2012 and 2011, Virginia Power capitalized AFUDC to property, plant and equipment of $33 million, $31 million and $31 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 2013, 2012 and 2011, Virginia Power recorded $32 million, $37 million and $20 million of AFUDC related to these projects, respectively.

For property subject to cost-of-service rate regulation, including Virginia Power 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 average composite depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2013		2012		2011
(percent)
Dominion
Generation		2.71		2.62		2.68
Transmission		2.36		2.17		2.26
Distribution		3.13		3.17		3.19
Storage		2.43		2.59		2.64
Gas gathering and processing		2.39		2.49		2.52
General and other		3.82		4.55		4.66
Virginia Power
Generation		2.71		2.62		2.68
Transmission		2.28		1.98		2.03
Distribution		3.33		3.32		3.33
General and other		3.51		4.32		4.38

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		44 years
Merchant generation-other		15 – 36 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.

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

75

Combined Notes to Consolidated Financial Statements, Continued

relevant market information is not available, fair value is estimated using discounted cash flow analyses. At least annually, the Companies evaluate the key assumptions underlying their AROs including estimates of the amounts and timing of future cash flows associated with retirement activities. AROs are adjusted when significant changes in these assumptions are identified. Dominion reports accretion of AROs and depreciation on asset retirement costs 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 and depreciation on asset retirement costs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs is reported in other operations and maintenance expense and depreciation 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.

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 AOCI. 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

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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 $7 million and $24 million at December 31, 2013 and December 31, 2012, respectively. Based on the average price of gas purchased during 2013 and 2012, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $77 million and $69 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 Illinois Gas Contracts

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

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

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

In the first and second quarters of 2013, Brayton Point’s and Kincaid’s assets and liabilities to be disposed were classified as

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

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

In August 2013, Dominion completed the sale and received proceeds of approximately $465 million, net of transaction costs. The sale resulted in a $35 million ($25 million after-tax) gain attributable to its equity method investment in Elwood, which is included in other income in Dominion’s Consolidated Statement of Income, which was partially offset by a $17 million ($18 million after-tax) loss attributable to Brayton Point and Kincaid, which includes a $16 million write-off of goodwill and is reflected in loss from discontinued operations in Dominion’s Consolidated Statement of Income. See Note 6 for other impairments related to these power stations.

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

Year Ended December 31,	2013			2012			2011
(millions)
Operating revenue	$	304		$	258		$	380
Loss before income taxes		(135	)(1)		(1,768	)(2)		(57	)

(1) Includes $64 million of charges related to the defeasance of Brayton Point debt and the early redemption of Kincaid debt in 2013. See Note 17 for more information.

(2) Includes a long-lived asset impairment charge of $1.6 billion.

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. Also 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 reported as discontinued operations in Dominion’s Consolidated Statements of Income:

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

(1) Includes long-lived asset impairment charges of $55 million in 2011.

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Combined Notes to Consolidated Financial Statements, Continued

NOTE 4. OPERATING REVENUE

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

Year Ended December 31,	2013		2012		2011
(millions)
Dominion
Electric sales:
Regulated	$	7,193	$	7,102	$	7,114
Nonregulated		2,511		2,483		2,721
Gas sales:
Regulated		323		250		287
Nonregulated		930		1,071		1,634
Gas transportation and storage		1,535		1,401		1,506
Other		628		528		503
Total operating revenue	$	13,120	$	12,835	$	13,765
Virginia Power
Regulated electric sales	$	7,193	$	7,102	$	7,114
Other		102		124		132
Total operating revenue	$	7,295	$	7,226	$	7,246

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% bonus depreciation allowance for qualifying capital expenditures incurred through 2013.

In September 2013, the IRS issued final regulations that provide guidance to taxpayers on the treatment of amounts paid to acquire, produce or improve tangible property, including whether expenditures should be deducted as repairs or capitalized and depreciated on tax returns. The final regulations include a number of safe harbor tax accounting methods which a taxpayer may choose to elect and, if adopted, will not be challenged by the IRS. In addition, the IRS reissued certain temporary regulations that were also issued concurrently as proposed regulations regarding property dispositions. The final regulations are effective for tax years beginning on or after January 1, 2014. Although changes in tax accounting methods would be effective prospectively, implementation of certain changes will require a calculation of the cumulative effect of the change on prior years. Under IRS procedural guidance issued in January 2014, if such cumulative effect increases taxable income, it is includible in taxable income over a four-year period, beginning with the year of the change. However, if such cumulative effect decreases taxable income, the entire amount is includible in taxable income in the year of the change.

Dominion and Virginia Power have evaluated tax accounting method changes that may be elected or required by the final regulations. At December 31, 2013, $17 million of deferred tax liabilities have been classified as current in the Companies’ Consolidated Balance Sheets, representing cumulative adjustment

amounts expected to be reflected in income for tax purposes during the twelve months ending December 31, 2014. Tax accounting method changes in 2014 are not expected to materially affect the Companies’ cash flows, results of operations or financial condition.

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,	2013			2012			2011			2013			2012			2011
(millions)
Current:
Federal	$	317		$	43		$	31		$	357		$	70		$	(35	)
State		110			84			16			62			81			79
Total current expense		427			127			47			419			151			44
Deferred:
Federal		497			645			685			224			482			484
State		(31	)		40			48			17			21			13
Total deferred expense		466			685			733			241			503			497
Amortization of deferred investment tax credits		(1	)		(1	)		(2	)		(1	)		(1	)		(1	)
Total income tax expense	$	892		$	811		$	778		$	659		$	653		$	540

(1) In 2012, Dominion’s current federal income tax expense for continuing and discontinued operations includes a $195 million benefit related to a carryback of its 2012 net operating loss. In 2011, Dominion’s deferred federal income tax expense includes the recognition of a $346 million benefit, including $51 million related to discontinued operations, for its 2011 net operating loss expected to be used to reduce taxable income in future years.

(2) In 2011, Virginia Power’s deferred federal income tax expense includes a $54 million benefit related to a portion of its 2011 net operating loss that is expected to be used in future years. Also, Virginia Power’s current federal income tax expense reflects the amounts of its 2011 net operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

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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,	2013			2012			2011			2013			2012			2011
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		2.1			4.2			1.9			3.1			3.9			4.4
Valuation allowances		(0.1	)		(0.7	)		—			—			—			—
Investment and production tax credits		(2.4	)		(0.5	)		(0.6	)		(0.2	)		—			—
AFUDC – equity		(0.6	)		(0.9	)		(0.6	)		(0.8	)		(0.9	)		(0.8	)
Employee stock ownership plan deduction		(0.6	)		(0.7	)		(0.6	)		—			—			—
Other, net		(0.4	)		(0.6	)		(0.7	)		(0.4	)		0.3			1.1
Effective tax rate		33.0	%		35.8	%		34.4	%		36.7	%		38.3	%		39.7	%

Dominion’s effective tax rate in 2012 reflects a $20 million reduction of a valuation allowance related to state operating loss carryforwards attributable to Fairless. After considering the results of Fairless’ operations in recent years and a forecast of future operating results reflecting Dominion’s planned purchase of the facility, Dominion concluded that it was more likely than not that the tax benefit of the operating losses would be realized. Dominion acquired Fairless in 2013 and will continue to evaluate the likelihood of realizing these tax benefits on a quarterly basis.

The Companies’ deferred income taxes consist of the following:

	Dominion						Virginia Power
At December 31,	2013			2012			2013			2012
(millions)
Deferred income taxes:
Total deferred income tax assets	$	2,142		$	2,505		$	462		$	466
Total deferred income tax liabilities		8,463			7,716			4,498			4,238
Total net deferred income tax liabilities	$	6,321		$	5,211		$	4,036		$	3,772
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	5,383		$	4,601		$	3,628		$	3,394
Nuclear decommissioning		1,136			994			441			407
Deferred state income taxes		606			474			285			265
Federal benefit of deferred state income taxes		(212	)		(166	)		(100	)		(93	)
Deferred fuel, purchased energy and gas costs		(33	)		3			(50	)		(16	)
Pension benefits		435			231			(52	)		(17	)
Other postretirement benefits		(78	)		(171	)		(3	)		(7	)
Loss and credit carryforwards		(797	)		(656	)		(106	)		(77	)
Valuation allowances		69			93			—			—
Partnership basis differences		125			174			—			—
Other		(313	)		(366	)		(7	)		(84	)
Total net deferred income tax liabilities	$	6,321		$	5,211		$	4,036		$	3,772

At December 31, 2013, Dominion had the following deductible loss and credit carryforwards:

• Federal loss carryforwards of $1.2 billion that expire if unutilized during the period 2021 through 2033;

• Federal investment tax credits of $58 million that expire if unutilized through 2033;

• Federal production and other tax credits of $45 million that expire if unutilized during the period 2031 through 2033;

• State loss carryforwards of $1.5 billion that expire if unutilized during the period 2014 through 2033. A valuation allowance on $763 million of these carryforwards has been established;

• State minimum tax credits of $133 million that do not expire; and

• State investment tax credits of $7 million that expire if unutilized through 2017.

At December 31, 2013, Virginia Power had the following deductible loss and credit carryforwards:

• Federal loss carryforwards of $282 million that expire if unutilized during the period 2031 through 2033;

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Combined Notes to Consolidated Financial Statements, Continued

• Federal production and other tax credits of $5 million that expire if unutilized during the period 2031 through 2033; and

• State loss carryforwards of $2 million that expire if unutilized during the period 2031 through 2033.

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:

	Dominion									Virginia Power
	2013			2012			2011			2013			2012			2011
(millions)
Balance at January 1	$	293		$	347		$	307		$	57		$	114		$	117
Increases—prior period positions		17			28			127			12			4			22
Decreases—prior period positions		(99	)		(106	)		(119	)		(42	)		(80	)		(51	)
Increases—current period positions		30			43			64			14			24			47
Decreases—current period positions		(5	)		—			(21	)		—			—			(21	)
Settlements with tax authorities		(2	)		(4	)		—			(2	)		(4	)		—
Expiration of statutes of limitations		(12	)		(15	)		(11	)		—			(1	)		—
Balance at December 31	$	222		$	293		$	347		$	39		$	57		$	114

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. For Dominion and its subsidiaries, these unrecognized tax benefits were $126 million, $167 million and $184 million at December 31, 2013, 2012 and 2011, respectively. For Dominion, the change in these unrecognized tax benefits decreased income tax expense by $29 million in 2013, and increased income tax expense by $1 million and $51 million in 2012 and 2011, respectively. For Virginia Power, these unrecognized tax benefits were $8 million, $13 million and $20 million at December 31, 2013, 2012 and 2011, respectively. For Virginia Power, the change in these unrecognized tax benefits increased income tax expense by $4 million, $1 million and $6 million in 2013, 2012 and 2011, respectively.

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 one that was subsequently settled in 2012.

The IRS examination of tax years 2008, 2009 and 2010 began in the first quarter of 2012 and was later expanded to

include the examination of the 2011 tax year. The audit concluded in late 2013, resulting in a payment of $46 million. However, the amount of a refund previously received by Dominion for its carryback of 2008 losses to 2007 was adjusted. The loss carryback, as adjusted, has been submitted to the Joint Committee for review. Dominion anticipates resolution of this matter early in 2014 with no further adjustments. Accordingly, except for 2007 and 2008, the earliest tax year remaining open for examination of Dominion’s federal tax returns is 2012.

Effective for its 2014 tax year, Dominion has been accepted into the CAP. The CAP is a method of identifying and resolving tax issues through open, cooperative, and transparent interaction between the IRS and taxpayers prior to the filing of a return. Through the CAP, Dominion will have the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions accepted by the IRS. Under a Pre-CAP plan, the IRS audit of tax years 2012 and 2013 will begin in early 2014.

With the audit protection afforded tax accounting method changes implemented under the September 2013 IRS regulations, settlement negotiations and expiration of statutes of limitations, it is reasonably possible that unrecognized tax benefits could decrease in 2014 by up to $115 million for Dominion and up to $25 million for Virginia Power. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by up to $65 million for Dominion and $7 million for Virginia Power.

Otherwise, with regard to 2013 and prior years, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2014.

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		2010
Connecticut		2010
Massachusetts		2008
Virginia(1)		2010
West Virginia		2010

(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.

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Discontinued Operations

Details of income tax expense for discontinued operations were as follows:

	Dominion
Year Ended December 31,	2013			2012			2011
(millions)
Current:
Federal		(274	)		(248	)		(41	)
State		(41	)		(6	)		(17	)
Total current benefit		(315	)		(254	)		(58	)
Deferred:
Federal		232			(368	)		10
State		40			(70	)		15
Total deferred expense (benefit)		272			(438	)		25
Total income tax benefit		(43	)		(692	)		(33	)

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

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.

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 daily mark-to-market valuations for the Companies’ derivative transactions using computer-based statistical models. 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 warehouse databases. The majority of forward prices are automatically uploaded into the data warehouse databases 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 mark-to-market valuations. During this meeting, the changes in mark-to-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

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Combined Notes to Consolidated Financial Statements, Continued

Ÿ Transaction prices

Ÿ Price volatility

Ÿ Price correlation

Ÿ Mean reversion

Ÿ Volumes

Ÿ Commodity location

Ÿ Load shaping

Ÿ Usage factors

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 (for alternative investments and common/collective trust funds)

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, common/collective trust 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 state-

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ments 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, mean reversion speeds, the original sales prices, and volumes. For Level 3 fair value measurements, the forward market prices, the implied price volatilities, price correlations, load shaping, mean reversion speeds 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.

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Combined Notes to Consolidated Financial Statements, Continued

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

	Fair Value (millions)		Valuation Techniques	Unobservable Input			Range		Weighted Average(1)
At December 31, 2013
Assets:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	14	Discounted Cash Flow		Market Price (per Dth)	(5)		(2) – 5		2
FTRs(3)		2	Discounted Cash Flow		Market Price (per MWh)	(5)		(1) – 5		—
Liquids(4)		6	Discounted Cash Flow		Market Price (per Gal)	(5)		1 – 3		1
Physical and Financial Options:
Natural Gas(2)		4	Option Model		Market Price (per Dth)	(5)		3 – 5		4
					Price Volatility	(6)		14% – 36%		20	%
					Price Correlation	(7)		(9%) – 100%		36	%
					Mean Reversion	(8)		.01 – 1		.53
Full Requirements Contracts:
Electricity		6	Discounted Cash Flow		Market Price (per MWh)	(5)		10 – 406(11)		42
					Load Shaping	(9)		0% – 10%		7	%
					Usage Factor	(10)		11% – 29%		16	%
Total assets	$	32
Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	19	Discounted Cash Flow		Market Price (per Dth)	(5)		(2) – 30		1
Electricity		1	Discounted Cash Flow		Market Price (per MWh)	(5)		28 – 240(11)		39
FTRs(3)		9	Discounted Cash Flow		Market Price (per MWh)	(5)		(1) – 5		1
Liquids(4)		11	Discounted Cash Flow		Market Price (per Gal)	(5)		1 – 3		1
Physical and Financial Options:
Natural Gas(2)		8	Option Model		Market Price (per Dth)	(5)		3 – 11		7
					Price Volatility	(6)		14% – 36%		20	%
					Price Correlation	(7)		(9%) – 100%		36	%
					Mean Reversion	(8)		.01 – 1		.53
Total liabilities	$	48

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Includes NGLs.

(5) Represents market prices beyond defined terms for Levels 1 and 2.

(6) Represents volatilities unrepresented in published markets.

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

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

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

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

(11) 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 Shaping	Sell(1)	Increase (decrease)		Loss (gain)
Usage Factor	Sell(2)	Increase (decrease)		Gain (loss)
Mean Reversion	Buy	Increase (decrease)		Loss (gain)
Mean Reversion	Sell	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

NATURAL GAS FACILITIES

In June 2013, Dominion purchased certain natural gas infrastructure facilities that were previously leased from third parties. The purchase price was based on terms in the lease, which exceeded current market pricing. As a result of the purchase price and expected losses, Dominion recorded an impairment charge of $49 million ($29 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write down the long-lived assets to their estimated fair values of less than $1 million. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of the assets in this impairment test. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs, including estimates of future production and other commodity prices.

84

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 was 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 loss from discontinued operations 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.

See Note 3 for information regarding the sale of Brayton Point, Kincaid and Dominion’s equity method investment in Elwood, including an additional impairment.

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 contracted to buy Kewaunee’s generation expired in December 2013 at a time of 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. Kewaunee ceased operations and decommissioning activities commenced in May 2013.

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.

As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of State Line’s long-lived assets. 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.

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 Statement 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 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 to write down these emissions allowances to their estimated fair value of less than $1 million. For Dominion, the $57 million ($34 million after-tax) charge was recorded partially in other operations and maintenance expense ($43 million, $26 million after-tax) and partially in loss from discontinued operations ($14 million, $8 million after-tax) in its Consolidated Statement of Income. For Virginia Power, the $43 million ($26 million after-tax) charge was recorded in other operations and maintenance expense in its Consolidated Statement of Income.

To estimate the value of these emissions allowances, Dominion utilized a market approach by obtaining broker quotes to validate CSAPR’s impact on emissions allowance prices. How-

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Combined Notes to Consolidated Financial Statements, Continued

ever, due to limited market activity for future SO₂ vintage year allowances, this was 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, 2013
Assets:
Derivatives:
Commodity	$	3	$	718	$	32	$	753
Interest rate		—		137		—		137
Investments(1):
Equity securities:
U.S.:
Large Cap		2,417		—		—		2,417
Other		79		—		—		79
Non-U.S.:
Large Cap		13		—		—		13
Fixed Income:
Corporate debt instruments		—		345		—		345
U.S. Treasury securities and agency debentures		415		175		—		590
State and municipal		—		343		—		343
Other		—		3		—		3
Cash equivalents and other		—		103		—		103
Restricted cash equivalents		—		8		—		8
Total assets	$	2,927	$	1,832	$	32	$	4,791
Liabilities:
Derivatives:
Commodity	$	3	$	1,051	$	48	$	1,102
Total liabilities	$	3	$	1,051	$	48	$	1,102
At December 31, 2012
Assets:
Derivatives:
Commodity	$	12	$	639	$	84	$	735
Interest rate		—		93		—		93
Investments(1):
Equity securities:
U.S.:
Large Cap		1,973		—		—		1,973
Other		59		—		—		59
Non-U.S.:
Large Cap		12		—		—		12
Fixed Income:
Corporate debt instruments		—		325		—		325
U.S. Treasury securities and agency debentures		391		152		—		543
State and municipal		—		315		—		315
Other		—		7		—		7
Cash equivalents and other		13		67		—		80
Restricted cash equivalents		—		33		—		33
Total assets	$	2,460	$	1,631	$	84	$	4,175
Liabilities:
Derivatives:
Commodity	$	8	$	528	$	59	$	595
Interest rate		—		66		—		66
Total liabilities	$	8	$	594	$	59	$	661

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

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:

	2013			2012			2011
(millions)
Balance at January 1,	$	25		$	(71	)	$	(50	)
Total realized and unrealized gains (losses):
Included in earnings		(9	)		(15	)		(77	)
Included in other comprehensive income (loss)		1			101			14
Included in regulatory assets/liabilities		(9	)		30			(42	)
Settlements		(23	)		47			88
Transfers out of Level 3		(1	)		(67	)		(4	)
Balance at December 31,	$	(16	)	$	25		$	(71	)
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

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, 2013
Total gains (losses) included in earnings	$	11		$	(19	)	$	(1	)	$	(9	)
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		1			—			(1	)		—
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

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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, 2013
Assets:
Derivatives:
Commodity	$	—	$	3	$	2	$	5
Interest rate		—		48		—		48
Investments(1):
Equity securities:
U.S.:
Large Cap		1,021		—		—		1,021
Other		36		—		—		36
Fixed Income:
Corporate debt instruments		—		191		—		191
U.S. Treasury securities and agency debentures		146		66		—		212
State and municipal		—		164		—		164
Cash equivalents and other		—		31		—		31
Restricted cash equivalents		—		8		—		8
Total assets	$	1,203	$	511	$	2	$	1,716
Liabilities:
Derivatives:
Commodity	$	—	$	3	$	9	$	12
Total Liabilities	$	—	$	3	$	9	$	12
At December 31, 2012
Assets:
Derivatives:
Commodity	$	—	$	1	$	5	$	6
Investments(1):
Equity securities:
U.S.:
Large Cap		779		—		—		779
Other		27		—		—		27
Fixed Income:
Corporate debt instruments		—		196		—		196
U.S. Treasury securities and agency debentures		168		66		—		234
State and municipal		—		118		—		118
Other		—		1		—		1
Cash equivalents and other		7		31		—		38
Restricted cash equivalents		—		10		—		10
Total assets	$	981	$	423	$	5	$	1,409
Liabilities:
Derivatives:
Commodity	$	—	$	6	$	3	$	9
Interest rate		—		25		—		25
Total Liabilities	$	—	$	31	$	3	$	34

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

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:

	2013			2012			2011
(millions)
Balance at January 1,	$	2		$	(28	)	$	14
Total realized and unrealized gains (losses):
Included in earnings		(17	)		(50	)		(45	)
Included in regulatory assets/liabilities		(9	)		30			(42	)
Settlements		17			50			45
Balance at December 31,	$	(7	)	$	2		$	(28	)

The gains and losses included in earnings in the Level 3 fair value category, including any 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, 2013, 2012 and 2011. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2013, 2012 and 2011.

Fair Value of Financial Instruments

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

At December 31,	2013				2012
	Carrying Amount		Estimated Fair  Value(1)		Carrying Amount		Estimated Fair  Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	18,396	$	19,887	$	16,841	$	19,898
Long-term debt, including securities due within one year—VIE(3)		—		—		860		864
Junior subordinated notes(3)		1,373		1,394		1,373		1,430
Remarketable subordinated notes(3)		1,080		1,192		—		—
Subsidiary preferred stock(4)		257		261		257		255
Virginia Power
Long-term debt, including securities due within one year(2)	$	8,032	$	8,897	$	6,669	$	8,270
Preferred stock(4)		257		261		257		255

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and

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Combined Notes to Consolidated Financial Statements, Continued

remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2) Carrying amount includes amounts which represent the unamortized discount and premium. At December 31, 2013, and 2012, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt, of approximately $55 million and $93 million, respectively.

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

(4) Includes deferred issuance expenses of $2 million at December 31, 2013 and 2012.

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.

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

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

DOMINION

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

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	137	$	—	$	137	$	93	$	—	$	93
Commodity contracts:
Over-the-counter		240		—		240		290		—		290
Exchange		506		—		506		416		—		416
Total derivatives, subject to a master netting or similar arrangement		883		—		883		799		—		799
Total derivatives, not subject to a master netting or similar arrangement		7		—		7		29		—		29
Total(1)	$	890	$	—	$	890	$	828	$	—	$	828

(1) At December 31, 2013, the total derivative asset balance contains $687 million of current assets, which is presented in current derivative assets, in Dominion’s Consolidated Balance Sheet, and $203 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $518 million of current assets, which is presented in current derivative assets in Dominion’s Consolidated Balance Sheet and $310 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet.

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			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	137	$	—	$	—	$	137	$	93	$	19	$	—	$	74
Commodity contracts:
Over-the-counter		240		63		—		177		290		97		—		193
Exchange		506		505		—		1		416		350		4		62
Total	$	883	$	568	$	—	$	315	$	799	$	466	$	4	$	329

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	66	$	—	$	66
Commodity contracts:
Over-the-counter		262		—		262		191		—		191
Exchange		838		—		838		393		—		393
Total derivatives, subject to a master netting or similar arrangement		1,100		—		1,100		650		—		650
Total derivatives, not subject to a master netting or similar arrangement		2		—		2		11		—		11
Total(1)	$	1,102	$	—	$	1,102	$	661	$	—	$	661

(1) At December 31, 2013, the total derivative liability balance contains $828 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet, and $274 million of noncurrent liabilities, which is presented in the other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $510 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet and $151 million of noncurrent liabilities, which is presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet.

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	—	$	66	$	19	$	—	$	47
Commodity contracts:
Over-the-counter		262		63		69		130		191		97		20		74
Exchange		838		505		333		—		393		350		43		—
Total	$	1,100	$	568	$	402	$	130	$	650	$	466	$	63	$	121

89

Combined Notes to Consolidated Financial Statements, Continued

The following table presents the volume of Dominion’s derivative activity as of December 31, 2013. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)		116		19
Basis(1)		466		281
Electricity (MWh):
Fixed price(1)		14,814,767		14,935,144
FTRs		41,316,345		437,384
Capacity (MW)		83,050		18,300
Liquids (gallons)(2)		151,200,000		—
Interest rate	$	2,050,000,000	$	750,000,000

(1) Includes options.

(2) Includes NGLs and oil.

For the years ended December 31, 2013, 2012 and 2011, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at December 31, 2013:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(3	)	$	(3	)		28 months
Electricity		(172	)		(124	)		36 months
Other		(3	)		(3	)		29 months
Interest rate		(110	)		(7	)		364 months
Total	$	(288	)	$	(137	)

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.

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:

	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At December 31, 2013
ASSETS
Current Assets
Commodity	$	49	$	522	$	571
Interest rate		116		—		116
Total current derivative assets		165		522		687
Noncurrent Assets
Commodity		28		154		182
Interest rate		21		—		21
Total noncurrent derivative assets(1)		49		154		203
Total derivative assets	$	214	$	676	$	890
LIABILITIES
Current Liabilities
Commodity	$	267	$	561	$	828
Total current derivative liabilities		267		561		828
Noncurrent Liabilities
Commodity		119		155		274
Total noncurrent derivative liabilities(2)		119		155		274
Total derivative liabilities	$	386	$	716	$	1,102
At December 31, 2012
ASSETS
Current Assets
Commodity	$	103	$	379	$	482
Interest rate		36		—		36
Total current derivative assets		139		379		518
Noncurrent Assets
Commodity		130		123		253
Interest rate		57		—		57
Total noncurrent derivative assets(1)		187		123		310
Total derivative assets	$	326	$	502	$	828
LIABILITIES
Current Liabilities
Commodity	$	103	$	341	$	444
Interest rate		66		—		66
Total current derivative liabilities		169		341		510
Noncurrent Liabilities
Commodity		58		93		151
Total noncurrent derivative liabilities(2)		58		93		151
Total derivative liabilities	$	227	$	434	$	661

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

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

90

The following tables present the gains and losses on Dominion’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified from AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Year Ended December 31, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	(58	)
Purchased gas					(47	)
Electric fuel and other energy-related purchases					(10	)
Total commodity	$	(481	)	$	(115	)	$	5
Interest rate(3)		77			(15	)		81
Total	$	(404	)	$	(130	)	$	86
Year Ended December 31, 2012
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	)

(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.

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2013			2012			2011
(millions)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue	$	(45	)	$	168		$	111
Purchased gas		(9	)		(14	)		(35	)
Electric fuel and other energy-related purchases		(29	)		(40	)		(45	)
Interest rate(2)		—			17			(5	)
Total	$	(83	)	$	131		$	26

(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.

91

Combined Notes to Consolidated Financial Statements, Continued

VIRGINIA POWER

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

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	48	$	—	$	48	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		4		—		4		6		—		6
Exchange		1		—		1		—		—		—
Total derivatives, subject to a master netting or similar arrangement		53		—		53		6		—		6
Total derivatives, not subject to a master netting or similar arrangement		—		—		—		—		—		—
Total(1)	$	53	$	—	$	53	$	6	$	—	$	6

(1) At December 31, 2013, the total derivative asset balance contains $53 million of current assets, which is presented in other current assets in Virginia Power’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $6 million of current assets, which is presented in other current assets in Virginia Power’s Consolidated Balance Sheet.

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	48	$	—	$	—	$	48	$	—	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		4		4		—		—		6		3		—		3
Exchange		1		—		—		1		—		—		—		—
Total	$	53	$	4	$	—	$	49	$	6	$	3	$	—	$	3

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	25	$	—	$	25
Commodity contracts:
Over-the-counter		12		—		12		7		—		7
Exchange		—		—		—		2		—		2
Total derivatives, subject to a master netting or similar arrangement		12		—		12		34		—		34
Total derivatives, not subject to a master netting or similar arrangement		—		—		—		—		—		—
Total(1)	$	12	$	—	$	12	$	34	$	—	$	34

(1) At December 31, 2013, the total derivative liability balance contains $12 million of current liabilities, which is presented in current derivative liabilities in Virginia Power’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $33 million of current liabilities, which is presented in current derivative liabilities in Virginia Power’s Consolidated Balance Sheet and $1 million of noncurrent derivative liabilities, which is presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheet.

92

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	—	$	25	$	—	$	—	$	25
Commodity contracts:
Over-the-counter		12		4		7		1		7		3		—		4
Exchange		—		—		—		—		2		—		2		—
Total	$	12	$	4	$	7	$	1	$	34	$	3	$	2	$	29

The following table presents the volume of Virginia Power’s derivative activity at December 31, 2013. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price		15		—
Basis		7		—
Electricity (MWh):
Fixed price		624,800		—
FTRs		39,186,609		—
Capacity (MW)		75,500		18,300
Interest rate	$	600,000,000	$	—

For the years ended December 31, 2013, 2012 and 2011, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to the time value of options and changes in the differences between spot prices and forward prices.

93

Combined Notes to Consolidated Financial Statements, Continued

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:

	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At December 31, 2013
ASSETS
Current Assets
Commodity	$	2	$	3	$	5
Interest rate		48		—		48
Total current derivative assets(1)		50		3		53
Total derivative assets	$	50	$	3	$	53
LIABILITIES
Current Liabilities
Commodity	$	1	$	11	$	12
Total current derivative liabilities		1		11		12
Total derivative liabilities	$	1	$	11	$	12
At December 31, 2012
ASSETS
Current Assets
Commodity	$	1	$	5	$	6
Total current derivative assets(1)		1		5		6
Total derivative assets	$	1	$	5	$	6
LIABILITIES
Current Liabilities
Commodity	$	5	$	3	$	8
Interest rate		25		—		25
Total current derivative liabilities		30		3		33
Noncurrent Liabilities
Commodity		1		—		1
Total noncurrent derivative liabilities(2)		1		—		1
Total derivative liabilities	$	31	$	3	$	34

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

(2) 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	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)
Year Ended December 31, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	—
Total commodity	$	—		$	—		$	5
Interest rate(3)		9			—			81
Total	$	9		$	—		$	86
Year Ended December 31, 2012
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	)

(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.

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2013			2012			2011
(millions)
Derivative Type and Location of Gains (Losses)
Commodity(2)	$	(16	)	$	(50	)	$	(45	)
Interest rate(3)		—			—			(5	)
Total	$	(16	)	$	(50	)	$	(50	)

(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.

94

NOTE 8. EARNINGS PER SHARE

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

	2013		2012		2011
(millions, except EPS)
Net income attributable to Dominion	$	1,697	$	302	$	1,408
Average shares of common stock outstanding-Basic		578.7		572.9		573.1
Net effect of dilutive securities(1)		0.8		1.0		1.5
Average shares of common stock outstanding-Diluted		579.5		573.9		574.6
Earnings Per Common Share-Basic	$	2.93	$	0.53	$	2.46
Earnings Per Common Share-Diluted	$	2.93	$	0.53	$	2.45

(1) Dilutive securities consist primarily of contingently convertible senior notes. See Note 17 for more information.

Dominion’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013 are potentially dilutive securities but were excluded from the calculation of diluted EPS for the year ended December 31, 2013. See Note 17 for more information. There were no potentially dilutive securities excluded from the calculation of diluted EPS for the years ended December 31, 2012 and 2011.

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 $107 million and $95 million at December 31, 2013 and 2012, respectively. Cost-method investments held in Dominion’s rabbi trusts totaled $10 million and $14 million at December 31, 2013 and 2012, 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)
2013
Marketable equity securities:
U.S.:
Large Cap	$	1,183	$	1,194	$	—		$	2,377
Other		49		23		—			72
Marketable debt securities:
Corporate debt instruments		332		16		(3	)		345
U.S. Treasury securities and agency debentures		589		8		(10	)		587
State and municipal		297		11		(5	)		303
Other		3		—		—			3
Cost method investments		106		—		—			106
Cash equivalents and other(2)		110		—		—			110
Total	$	2,669	$	1,252	$	(18	)(3)	$	3,903
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

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

(2) Includes pending sales of securities of $11 million and pending purchases of securities of $6 million at December 31, 2013 and 2012, respectively.

(3) The fair value of securities in an unrealized loss position was $604 million and $195 million at December 31, 2013 and 2012, respectively.

95

Combined Notes to Consolidated Financial Statements, Continued

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at December 31, 2013 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	128
Due after one year through five years		357
Due after five years through ten years		362
Due after ten years		391
Total	$	1,238

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

Year Ended December 31,	2013		2012		2011
(millions)
Proceeds from sales	$	1,476	$	1,356	$	1,757
Realized gains(1)		157		98		79
Realized losses(1)		33		33		92

(1) 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,	2013			2012			2011
(millions)
Total other-than-temporary impairment losses(1)	$	31		$	26		$	75
Losses recorded to decommissioning trust regulatory liability		(13	)		(10	)		(24	)
Losses recognized in other comprehensive income (before taxes)		(10	)		(2	)		(3	)
Net impairment losses recognized in earnings	$	8		$	14		$	48

(1) Amounts include other-than-temporary impairment losses for debt securities of $18 million, $4 million and $6 million at December 31, 2013, 2012 and 2011, 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,				2013		2012
(millions)
Blue Racer Midstream LLC		50	%	$	510	$	39	Midstream gas and related services
Fowler I Holdings LLC		50	%		149		158	Wind-powered merchant generation facility
NedPower Mount Storm LLC		50	%		131		137	Wind-powered merchant generation facility
Iroquois Gas Transmission System, LP		24.72	%		105		102	Gas transmission system
Elwood Energy LLC(1)		—	%		—		117	Natural gas-fired merchant generation peaking facility
Other(2)		various			21		5
Total				$	916	$	558

(1) Following the 2013 sale of Elwood, at December 31, 2013, Dominion retained a 0.5% cost method investment. At December 31, 2012, Dominion owned 50% and Elwood was therefore considered an equity method investment.

(2) Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018.

Dominion’s equity earnings on these investments totaled $14 million, $25 million and $35 million in 2013, 2012 and 2011, respectively. Dominion received distributions from these investments of $33 million, $58 million and $55 million in 2013, 2012, and 2011, respectively. As of December 31, 2013 and 2012, the carrying amount of Dominion’s investments exceeded Dominion’s share of underlying equity in net assets by approximately $36 million and $30 million, respectively. $28 million of 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, which are being amortized over the useful lives of the underlying assets. The remaining $8 million of differences reflect equity method goodwill and are not being amortized.

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.

In March 2013, Dominion sold Line TL-404 to Blue Racer and received approximately $47 million in cash proceeds resulting in an approximately $25 million ($14 million after-tax) gain. Phase 1 of the Natrium natural gas processing and fractionation facility was completed in the second quarter of 2013 and was contributed to Blue Racer in the third quarter of 2013, resulting in an increased equity method investment in Blue Racer of $473 million. Also in the third quarter of 2013, Dominion sold Line TPL-2A and Line TL-388 to Blue Racer and received approximately $83 million in cash proceeds resulting in an approximately $75 million ($42 million after-tax) gain. In the fourth quarter of 2013, Dominion sold the Western System to Blue Racer for $30 million in cash proceeds resulting in an approximately $4 million ($2 million after-tax) gain. Dominion NGL Pipelines, LLC was contributed in January 2014 to Blue Racer prior to commencement of service, resulting in an increased equity method investment of $155 million.

The joint venture is leveraging 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 include gathering, processing, fractionation, and NGL transportation and marketing. In addition to the assets already sold or contributed, Dominion expects to sell additional East Ohio gathering assets to Blue Racer.

96

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)
2013
Marketable equity securities:
U.S.:
Large Cap	$	506	$	514	$	—		$	1,020
Other		25		11		—			36
Marketable debt securities:
Corporate debt instruments		185		8		(2	)		191
U.S. Treasury securities and agency debentures		214		1		(3	)		212
State and municipal		163		4		(4	)		163
Cost method investments		106		—		—			106
Cash equivalents and other(2)		37		—		—			37
Total	$	1,236	$	538	$	(9	)(3)	$	1,765
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

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

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

(3) The fair value of securities in an unrealized loss position was $299 million and $104 million at December 31, 2013 and 2012, respectively.

The fair value of Virginia Power’s debt securities at December 31, 2013, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	31
Due after one year through five years		163
Due after five years through ten years		196
Due after ten years		176
Total	$	566

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

Year Ended December 31,	2013		2012		2011
(millions)
Proceeds from sales	$	572	$	626	$	1,030
Realized gains(1)		52		42		34
Realized losses(1)		14		11		34

(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,	2013			2012			2011
(millions)
Total other-than-temporary impairment losses(1)	$	15		$	11		$	29
Losses recorded to decommissioning trust regulatory liability		(13	)		(10	)		(24	)
Losses recorded in other comprehensive income (before taxes)		(1	)		—			(1	)
Net impairment losses recognized in earnings	$	1		$	1		$	4

(1) Amounts include other-than-temporary impairment losses for debt securities of $9 million, $2 million and $4 million at December 31, 2013, 2012 and 2011, 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, 2013 and 2012, Dominion had $11 million and $37 million, respectively, and Virginia Power had $8 million and $10 million, respectively, of restricted cash and cash equivalents. These balances are presented in Other Current Assets and Other Investments in the Consolidated Balance Sheets.

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Combined Notes to Consolidated Financial Statements, Continued

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,	2013		2012
(millions)
Dominion
Utility:
Generation	$	14,018	$	13,707
Transmission		8,686		7,799
Distribution		11,714		11,071
Storage		2,190		2,137
Nuclear fuel		1,375		1,277
Gas gathering and processing		787		803
General and other		812		803
Other-including plant under construction		3,261		2,232
Total utility		42,843		39,829
Nonutility:
Merchant generation—nuclear		1,153		1,163
Merchant generation—other(1)		1,328		1,289
Nuclear fuel		770		775
Other-including plant under construction		875		1,265
Total nonutility		4,126		4,492
Total property, plant and equipment	$	46,969	$	44,321
Virginia Power
Utility:
Generation	$	14,018	$	13,707
Transmission		4,959		4,261
Distribution		9,103		8,701
Nuclear fuel		1,375		1,277
General and other		668		659
Other-including plant under construction		2,719		2,017
Total utility		32,842		30,622
Nonutility-other		6		9
Total property, plant and equipment	$	32,848	$	30,631

(1) 2012 amount includes $957 million due to consolidation of a VIE. See Note 15 for further information.

Jointly-Owned Power Stations

Dominion’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2013 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	$	1,038		$	2,486		$	568		$	1,007
Accumulated depreciation		(536	)		(1,109	)		(199	)		(262	)
Nuclear fuel		—			597			—			388
Accumulated amortization of nuclear fuel		—			(434	)		—			(283	)
Plant under construction		23			76			6			69

(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.

Assignment of Marcellus Acreage

In December 2013, DTI closed on agreements with two natural gas producers to convey approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. The agreements provide for payments to DTI, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013, Dominion received approximately $100 million in cash proceeds, resulting in an approximately $20 million ($12 million-after tax) gain and approximately $80 million deferred revenue, which will be recognized over the remaining terms of the agreements.

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(1)		Total
(millions)
Balance at December 31, 2011(2)	$	1,503	(3)	$	712		$	926	(3)	$	—	$	3,141
Asset disposition adjustment		—			(11	)(5)		—			—		(11	)
Balance at December 31, 2012(2)	$	1,503		$	701		$	926		$	—	$	3,130
Asset disposition adjustment		(19	)(4)		(25	)(5)		—			—		(44	)
Balance at December 31, 2013(2)	$	1,484		$	676		$	926		$	—	$	3,086

(1) Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.

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

(3) Recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

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

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

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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 $72 million, $82 million and $78 million for 2013, 2012 and 2011, respectively. In 2013, Dominion acquired $81 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 10 years. Amortization expense for Virginia Power’s intangible assets was $22 million for 2013, 2012, and 2011. In 2013, Virginia Power acquired $14 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 5 years. The components of intangible assets are as follows:

At December 31,	2013				2012
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion
Software, licenses and other	$	867	$	308	$	859	$	327
Emissions allowances		3		2		5		1
Total	$	870	$	310	$	864	$	328
Virginia Power
Software, licenses and other	$	271	$	78	$	303	$	122
Total	$	271	$	78	$	303	$	122

Annual amortization expense for these intangible assets is estimated to be as follows:

	2014		2015		2016		2017		2018
(millions)
Dominion	$	69	$	59	$	50	$	40	$	29
Virginia Power	$	21	$	15	$	12	$	9	$	5

NOTE 12. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities include the following:

At December 31,	2013		2012
(millions)
Dominion
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	89	$	55
Unrecovered gas costs(2)		50		59
Virginia sales taxes(3)		46		37
Derivatives(4)		16		—
Plant retirement(5)		1		25
Other		15		27
Regulatory assets-current(6)		217		203
Unrecognized pension and other postretirement benefit costs(7)		706		1,210
Deferred rate adjustment clause costs(1)		287		173
Income taxes recoverable through future rates(8)		155		140
Derivatives(4)		16		105
Other postretirement benefit costs(9)		12		21
Plant retirement(5)		10		11
Other		42		57
Regulatory assets-non-current		1,228		1,717
Total regulatory assets	$	1,445	$	1,920
Regulatory liabilities:
PIPP(10)	$	76	$	100
Deferred cost of fuel used in electric generation(11)		24		7
Other		28		29
Regulatory liabilities-current(12)		128		136
Provision for future cost of removal and AROs(13)		1,028		985
Decommissioning trust(14)		693		501
Unrecognized pension and other postretirement benefit costs(7)		174		2
Deferred cost of fuel used in electric generation(11)		90		13
Other		16		13
Regulatory liabilities-non-current		2,001		1,514
Total regulatory liabilities	$	2,129	$	1,650
Virginia Power
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	62	$	51
Virginia sales taxes(3)		46		37
Derivatives(4)		16		—
Plant retirement(5)		1		25
Other		3		6
Regulatory assets-current		128		119
Deferred rate adjustment clause costs(1)		227		127
Income taxes recoverable through future rates(8)		124		110
Derivatives(4)		16		105
Plant retirement(5)		10		11
Other		40		43
Regulatory assets-non-current		417		396
Total regulatory assets	$	545	$	515
Regulatory liabilities:
Deferred cost of fuel used in electric generation(11)	$	24	$	7
Other		17		25
Regulatory liabilities-current		41		32
Provision for future cost of removal(13)		807		763
Decommissioning trust(14)		693		501
Deferred cost of fuel used in electric generation(11)		90		14
Other		7		7
Regulatory liabilities-non-current		1,597		1,285
Total regulatory liabilities	$	1,638	$	1,317

  (1) Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for more information.

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

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Combined Notes to Consolidated Financial Statements, Continued

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

  (6) Current regulatory assets are presented in other current assets in Dominion’s Consolidated Balance Sheets.

  (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) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power’s generation operations. For 2013, amount includes approximately $5 million related to DOE claims. See Note 13 for more information.

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

(13) 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.

(14) 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, 2013, approximately $129 million of Dominion’s and $63 million of Virginia Power’s regulatory assets represented past expenditures on which they do not currently earn a return. The majority of 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 estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range

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

FERC—Electric

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

Rates

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

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 2014 is $857 million and the remaining projects were completed by 2012. Numerous parties sought rehearing of the FERC order in August 2008. In May 2012, FERC issued an order denying the rehearing requests. In July 2012, the North Carolina Commission filed an appeal of the FERC orders with the U.S. Court of Appeals for the Fourth Circuit. In January 2014, the court rejected the appeal and affirmed FERC’s decision granting the incentives.

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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.

Other Regulatory Matters

Electric Regulation in Virginia

The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers.

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, and also constitutes statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly proposed generation projects.

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.

2013 Biennial Review

Pursuant to the Regulation Act, in March 2013, Virginia Power submitted its base rate filings and accompanying schedules in support of the Virginia Commission’s 2013 biennial review of Virgina Power’s rates, terms and conditions, as well as of Virginia Power’s earnings for 2011 and 2012 test periods. The Virginia Power earnings test analysis reviewed by the Virginia Commission reflected an ROE of 10.30% on its generation and distribution services earnings for the combined test periods.

In November 2013, the Virginia Commission issued its 2013 Biennial Review Order. After deciding eleven contested earnings test adjustments, the Virginia Commission ruled that Virginia Power earned on average an ROE of approximately 10.25% on its generation and distribution services for the combined 2011 and 2012 test periods. Because this ROE was more than 50 basis points below Virginia Power’s authorized ROE of 10.9%, the Virginia Commission authorized the deferred recovery, for earnings test purposes, of $23 million in costs related to asset impairments with early retirement decisions, severe weather events, and natural disasters to be amortized over the 2013 calendar year. The Virginia Commission did not order a base rate increase because Virginia Power had previously waived its right to any such increase, and because it determined that Virginia Power had a revenue sufficiency of approximately $280 million when projecting the annual revenues generated by base rates to the revenues required to cover costs of service and earn a fair return. As part of its revenue sufficiency determination, the Virginia Commission also made findings on eleven rate case adjustments, in addition to changes to the cost of capital and capital structure, which resulted in changes to Virginia Power’s rate year revenues and expenses, and Virginia Power’s rate base for generation and distribution, for the rate year beginning January 1, 2014. Virginia Power incurred a $55 million ($37 million after-tax) charge in connection with the 2013 Biennial Review Order.

In its 2013 Biennial Review Order, the Virginia Commission also set the ROE that will be used in Virginia Power’s 2015 biennial review earnings test analysis for earnings on generation and distribution services for the combined 2013 and 2014 test periods, and that will be applied to Riders R, S, W, B, BW, C1A, and C2A. Pursuant to the Regulation Act, Virginia Power’s authorized ROE can be no lower than the average of the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., subject to certain limitations as described in the Regulation Act. Following this statutory peer group analysis, the Virginia Commission determined that the peer group floor ROE for Virginia Power was 9.89%. It further held, declining to increase or decrease Virginia Power’s combined rate of return based on performance, that Virginia Power’s ROE for earnings test purposes in its 2015 biennial review and for rate adjustment clause purposes is 10.0%, consistent with its determination that Virginia Power’s market cost of equity is 10.0%.

Virginia Fuel Expenses

In May 2013, Virginia Power submitted its annual fuel factor filing to the Virginia Commission, proposing an increase of approximately $162 million in fuel revenue for the rate year beginning July 1, 2013. In June 2013, the Virginia Commission issued an order approving the rate.

In November 2013, the Virginia Commission approved Virginia Power’s voluntary request to reduce Virginia Power’s currently-approved fuel factor rate from 2.942 ¢/kWh to 2.572 ¢/kWh effective for usage on and after December 1, 2013, due to an expected over-recovery of fuel costs. This request is expected to reduce Virginia Power’s anticipated fuel recoveries through June 30, 2014 by more than $140 million. At December 31,

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Combined Notes to Consolidated Financial Statements, Continued

2013, Virginia Power’s Consolidated Balance Sheets reflected $24 million of other current liabilities and $85 million of noncurrent regulatory liabilities related to the over-recovered fuel costs.

Rate Adjustment Clauses

Below is a discussion of significant riders associated with various Virginia Power projects:

Ÿ In 2012, the Virginia Commission approved the conversion of the Altavista, Hopewell, and Southampton power stations to biomass, and in conjunction approved Rider B. Virginia Power proposed an approximately $16 million revenue requirement for the rate year beginning April 1, 2014. This case is pending.

Ÿ In 2013, the Virginia Commission approved Virginia Power’s request to construct and operate Brunswick County, and in conjunction approved the associated transmission facilities and Rider BW. Virginia Power proposed an approximately $101 million revenue requirement for the rate year beginning September 1, 2014. This case is pending.

Ÿ The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. Virginia Power proposed an approximately $248 million revenue requirement for the rate year beginning April 1, 2014. This case is pending.

Ÿ The Virginia Commission previously approved Rider W in conjunction with Warren County. Virginia Power proposed an approximately $101 million total revenue requirement for the rate year beginning April 1, 2014. This case is pending.

Ÿ The Virginia Commission approved Riders C1A and C2A in connection with various DSM programs. The requested revenue requirements are approximately $1 million for Rider C1A and approximately $35 million for Rider C2A. This case is pending.

Ÿ In May 2013, Virginia Power filed for an adjustment to its current Rider T1 with the Virginia Commission for the rate year beginning September 1, 2013, which reflects a total revenue requirement of approximately $404 million. In July 2013, the Virginia Commission issued an order approving the rate.

Bremo Power Station

In September 2013, the Virginia Commission issued its final order approving an amended and reissued CPCN that would allow Virginia Power to convert Bremo Units 3 and 4 from using coal to natural gas as their fuel source. The proposed conversion will preserve 227 MW (net) of existing capacity and is expected to cost approximately $53 million, excluding financing costs.

North Anna

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

If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power filed the first of its two-part amendment to the COL application with the NRC in July 2013 to reflect the ESBWR technology, and filed the second part of the amendment in December 2013. A COL is expected in 2015. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

In May 2013, BREDL filed a motion with the NRC ASLB to reopen the COL adjudicatory proceeding relating to North Anna based on new information, citing the change in reactor technology. The motion did not propose any new contentions but asked that either (i) the proceeding be restarted from the beginning by submittal of a new application and renoticing in the Federal Register, or (ii) the proceeding be reopened pending submittal of new contentions, which BREDL would be given an extended amount of time to file.

In July 2013, the ASLB issued an order holding BREDL’s motion in abeyance. The ASLB noted that because BREDL proposed no contentions, it could not determine whether any portion of the motion falls within the ASLB’s jurisdiction, which is currently limited to ruling on a September 2011 petition filed by BREDL to reopen the COL proceeding related to seismic issues. In January 2014, Virginia Power informed the ASLB and parties that the Company’s assessment of seismic issues was complete. Under a previous ruling of the ASLB, BREDL will have a period of 60 days from the time Virginia Power informs the NRC and parties that its seismic assessment is complete to submit a motion to reopen the proceeding on this topic.

Legislation has been proposed that would limit the portion of costs incurred by an investor-owned electric utility between July 1, 2007 and December 31, 2013, in developing a nuclear power facility or an offshore wind project that are recoverable from Virginia jurisdictional and non-jurisdictional customers through a future rate adjustment clause to a maximum of 30% of such amount. Virginia Power has deferred or capitalized costs totaling $570 million as of December 31, 2013 related to the development of a third nuclear unit site located at North Anna. If this proposed legislation is enacted, 70% of the costs previously deferred or capitalized would be recovered from Virginia jurisdictional and non-jurisdictional ratepayers as part of the 2013 and 2014 base rates. Upon enactment, Virginia Power would recognize 70% of the costs previously deferred or capitalized against net income in 2014. The remaining deferred or capitalized costs, as well as costs incurred after December 31, 2013, would continue to be eligible for inclusion in a future rate adjustment clause.

Electric Transmission Projects

In January 2013, a notice of appeal was filed with the Supreme Court of Virginia by a private party regarding the Virginia Commission’s December 2012 order granting a CPCN and authorizing construction of the Waxpool-Brambleton-BECO line. In October 2013, the Supreme Court of Virginia issued an opinion affirming the Virginia Commission’s decision.

In October 2013, Virginia Power applied for a CPCN to rebuild within existing rights-of-way its existing 500 kV Loudoun-Pleasant View transmission line in Loudoun County. As stated in the application, the project is needed to address NERC Reliability Standards violations projected to occur in 2016 and to replace aging transmission facilities. This case is pending.

In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry Switching Station in Surry County to a new Skiffes Creek Switching Station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed

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new Skiffes Creek Switching Station to Virginia Power’s existing Whealton Substation in the City of Hampton. In December 2013, Virginia Power filed a motion for reconsideration to the Virginia Commission and a notice to appeal the Virginia Commission’s order to the Supreme Court of Virginia. The Virginia Commission granted reconsideration and ordered a hearing, which was held in January 2014. The matter is pending at the Virginia Commission. The projected in-service date for this transmission project has been delayed until December 2015 at the earliest.

Ohio Regulation

PIR Program

In 2008, East Ohio began PIR, aimed at replacing approximately 20% of its pipeline system, or approximately 4,100 miles, over a 25-year period. In February 2013, East Ohio filed an application with the Ohio Commission to adjust the cost recovery charge for costs associated with PIR investments for the calendar year 2012 and cumulatively. The application includes total gross plant investment for 2012 of $148 million, cumulative gross plant investment of $511 million, and a revenue requirement of $67 million. The Ohio Commission issued an order approving the rates in April 2013. In May 2013, the approved PIR cost recovery rates became effective.

In November 2013, East Ohio filed a notice to adjust the PIR cost recovery for 2013 costs. The filing reflects projected gross plant investment for 2013 of $170 million, cumulative gross plant investment of $681 million and an estimated revenue requirement of approximately $90 million. This case is pending.

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 payment plan amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. In July 2013, the Ohio Commission approved East Ohio’s annual update of the PIPP Rider, which reflects the refund over the next year of an over-recovery of accumulated arrearages of approximately $91 million as of March 31, 2013, net of projected deferred program costs of approximately $54 million for the period from April 2013 through June 2014.

FERC Regulation

DTI Fuel Settlement

In mid-2013, DTI received concerns about its fuel retainage percentages and apparent over-recovery of fuel costs during certain time periods reflected in its annual fuel reports. In December 2013, DTI submitted for FERC approval a stipulation and agreement addressing, among other things, reductions in its fuel retainage percentages.

In February 2014, FERC approved the stipulation and agreement. DTI will implement the reduced fuel retainage percentages effective March 1, 2014. DTI will also provide refunds with interest to each settling customer reflecting the value of the actual quantities of fuel retained from that party between January 1, 2014 and the March 1, 2014 implementation date. This agreement is expected to reduce DTI’s revenues by approximately $35 million in 2014.

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Combined Notes to Consolidated Financial Statements, Continued

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 2012 and 2013 were as follows:

	Amount
(millions)
Dominion
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(2)		242
Accretion		77
Other		(23	)
AROs at December 31, 2012(1)	$	1,705
Obligations incurred during the period		13
Obligations settled during the period		(68	)
Revisions in estimated cash flows(3)		(129	)
Accretion		86
Other		(29	)
AROs at December 31, 2013(1)	$	1,578
Virginia Power
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
Obligations incurred during the period		2
Obligations settled during the period		(2	)
Revisions in estimated cash flows(3)		(52	)
Accretion		38
Other		(2	)
AROs at December 31, 2013	$	689

(1) Includes $15 million, $64 million and $94 million reported in other current liabilities at December 31, 2011, 2012, and 2013, respectively.

(2) Primarily reflects the accelerated timing of the decommissioning of Kewaunee that began in 2013.

(3) Primarily reflects lower anticipated nuclear decommissioning costs.

(4) Includes $1 million reported in other current liabilities.

(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, 2013 and 2012, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $3.9 billion and $3.3 billion, respectively. At December 31, 2013 and 2012, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.8 billion and $1.5 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 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 $864 million as of December 31, 2013. Virginia Power paid $217 million, $214 million, and $211 million for electric capacity and $98 million, $83 million, and $125 million for electric energy to these entities for the years ended December 31, 2013, 2012 and 2011, respectively.

Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $331 million, $328 million, and $389 million for the years ended December 31, 2013, 2012 and 2011, respectively. Virginia Power determined that it is not the most closely associated entity with DRS and therefore not the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power. Virginia Power has no obligation to absorb more than its allocated share of DRS costs.

104

Through August 2013, Dominion leased the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. Dominion made annual lease payments of approximately $53 million.

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

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

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

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

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.

DOMINION

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

	Facility Limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Capacity Available
(millions)
At December 31, 2013
Joint revolving credit facility(1)	$	3,000	$	1,927		$	—	$	1,073
Joint revolving credit facility(2)		500		—			11		489
Total	$	3,500	$	1,927	(3)	$	11	$	1,562
At December 31, 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

(1) Effective September 2013, the maturity date was extended from September 2017 to September 2018. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.

(2) Effective September 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were 0.33% and 0.49% at December 31, 2013 and 2012, respectively.

105

Combined Notes to Consolidated Financial Statements, Continued

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:

	Facility Sub-limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Sub-limit Capacity Available
(millions)
At December 31, 2013
Joint revolving credit facility(1)	$	1,000	$	842		$	—	$	158
Joint revolving credit facility(2)		250		—			1		249
Total	$	1,250	$	842	(3)	$	1	$	407
At December 31, 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

(1) Effective September 2013, the maturity date was extended from September 2017 to September 2018. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.

(2) Effective September 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s 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 0.33% and 0.47% at December 31, 2013 and 2012, respectively.

106

In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility. Effective September 2013, the maturity date was extended from September 2017 to September 2018. As of December 31, 2013, this facility supports approximately $119 million of certain variable rate tax-exempt financings of Virginia Power.

NOTE 17. LONG-TERM DEBT

At December 31,	2013 Weighted- average Coupon(1)			2013			2012
(millions, except percentages)
Virginia Electric and Power Company:
Unsecured Senior Notes:
1.2% to 8.625%, due 2013 to 2018		5.09	%	$	2,138		$	2,306
2.75% to 8.875%, due 2019 to 2043		5.25	%		4,993			3,408
Tax-Exempt Financings(2):
Variable rates, due 2016 to 2041		0.98	%		606			454
1.5% to 5.6%, due 2022 to 2040		3.16	%		306			508
Virginia Electric and Power Company total principal				$	8,043		$	6,676
Securities due within one year		4.10	%		(58	)		(418	)
Unamortized discount and premium, net					(11	)		(7	)
Virginia Electric and Power Company total long-term debt				$	7,974		$	6,251
Dominion Resources, Inc.:
Unsecured Senior Notes:
Variable rates, due 2013 and 2014		0.37	%	$	400		$	400
1.4% to 7.195%, due 2013 to 2018		4.03	%		3,291			3,541
2.75% to 8.875%, due 2019 to 2042(3)		5.64	%		4,599			4,599
Unsecured Convertible Senior Notes, 2.125%, due 2023(4)					43			82
Tax-Exempt Financing, variable rate, due 2041(5)		1.12	%		75			—
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031		8.40	%		10			268
Enhanced Junior Subordinated Notes:
7.5% and 8.375%, due 2064 and 2066		8.11	%		985			985
Variable rate, due 2066		2.58	%		380			380
Remarketable Subordinated Notes, 1.07% and 1.18%, due 2019 and 2021		1.13	%		1,100			—
Unsecured Debentures and Senior Notes(6):
5.0% and 6.625%, due 2013 and 2014		5.00	%		600			622
6.8% and 6.875%, due 2026 and 2027		6.81	%		89			89
Dominion Gas Holdings, LLC:
Unsecured Senior Notes, 1.05% to 4.8%, due 2016 to 2043		3.13	%		1,200			—
Dominion Energy, Inc.:
Secured Senior Notes:
5.03% to 5.78%, due 2013(7)					—			842
7.33%, due 2020(8)					—			145
Tax-Exempt Financings:
2.25% to 5.75%, due 2033 to 2042(9)		2.38	%		27			284
Variable rate, due 2041(5)					—			75
Virginia Electric and Power Company total principal (from above)					8,043			6,676
Dominion Resources, Inc. total principal				$	20,842		$	18,988
Fair value hedge valuation(10)					55			93
Securities due within one year(11)		2.95	%		(1,519	)		(2,223	)
Unamortized discount and premium, net					(48	)		(7	)
Dominion Resources, Inc. total long-term debt				$	19,330		$	16,851

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2013.

(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 2018.

(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, 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) Debt issued by the MDFA on behalf of Brayton Point. In connection with the sale of Brayton Point, the sole obligor under the bonds was changed from Brayton Point to Dominion in June 2013.

107

Combined Notes to Consolidated Financial Statements, Continued

(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 of unamortized premium in 2012. The debt was non-recourse to Dominion and was secured by Juniper’s assets. Dominion’s purchase of Fairless in August 2013 resulted in the removal of the debt from Dominion’s Consolidated Balance Sheet. See Note 15 for additional information.

(8) Represented debt associated with Kincaid. The debt was non-recourse to Dominion and was secured by the facility’s assets and revenue. In connection with the sale of Kincaid, the notes were redeemed in May 2013 for approximately $185 million, including a make-whole premium and accrued interest.

(9) In 2012 included debt issued by the MDFA on behalf of Brayton Point. In connection with the sale of Brayton Point, three series of bonds totaling approximately $257 million were defeased in June 2013. In June 2013, Brayton Point delivered approximately $284 million to fund an irrevocable trust for the purpose of paying maturing principal and interest due through and including the earliest redemption dates of the bonds in 2016 and 2019.

(10) Represents the valuation of certain fair value hedges associated with Dominion’s fixed rate debt.

(11) Includes $14 million fair value hedge valuation in 2013 and $23 million of net unamortized premium and fair value hedge valuation in 2012.

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, 2013, were as follows:

	2014			2015			2016			2017			2018			Thereafter			Total
(millions, except percentages)
Virginia Power	$	58		$	211		$	476		$	679		$	850		$	5,769		$	8,043
Weighted-average Coupon		4.10	%		5.39	%		5.25	%		5.44	%		4.17	%		4.78	%
Dominion
Unsecured Senior Notes	$	1,465		$	960		$	1,752		$	1,303		$	1,350		$	10,523		$	17,353
Tax-Exempt Financings		40			—			19			75			—			880			1,014
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts		—			—			—			—			—			10			10
Enhanced Junior Subordinated Notes		—			—			—			—			—			1,365			1,365
Remarketable Subordinated Notes		—			—			—			—			—			1,100			1,100
Total	$	1,505		$	960		$	1,771		$	1,378		$	1,350		$	13,878		$	20,842
Weighted-average Coupon		2.95	%		4.45	%		3.51	%		4.55	%		4.99	%		4.90	%

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, 2013, there were no events of default under these covenants.

In February 2014, Virginia Power issued $350 million of 3.45% senior notes, and $400 million of 4.45% senior notes, that mature in 2024, and 2044, respectively.

Convertible Securities

At December 31, 2013, Dominion had $43 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominion’s common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. The conversion rate is subject to adjustment 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, 2013, the conversion rate had been adjusted to 29.8780 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $33.47, primarily due to individual dividend payments above the level paid at issuance. If the outstanding notes as of December 31, 2013 were all converted, it would result in the issuance of approximately 600 thousand additional shares of common stock. In January 2014, Dominion’s Board of Directors declared dividends payable March 20, 2014 of 60 cents per share of common stock which will increase the conversion rate to 29.9961 effective as of February 26, 2014.

The senior notes are eligible for conversion during any calendar quarter when the closing price of Dominion’s common stock was equal to or higher than 120% of the conversion price for at

least 20 out of the last 30 consecutive trading days of the preceding quarter, the notes are called for redemption by Dominion and upon the occurrence of certain other conditions. During 2013, the senior notes were eligible for conversion and approximately $39 million of the notes were converted by holders into $28 million of common stock. The senior notes are eligible for conversion during the first quarter of 2014. 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 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.

108

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

The following table provides summary information about the capital securities and junior subordinated notes outstanding as of December 31, 2013:

Date Established	Capital Trust	Units		Rate			Capital Securities Amount		Common Securities Amount
		(thousands)					(millions)
January 2001	Dominion Resources Capital Trust III(1)		10		8.4	%	$	10	$	0.3

(1) $10 million—Dominion Resources, Inc. 8.4% Debentures due 1/15/2031 were held as assets by the capital trust.

Interest charges related to Dominion’s junior subordinated notes payable to affiliated trusts were $1 million for the year ended December 31, 2013 and $21 million for the years ended December 31, 2012 and 2011.

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 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 December 2011, 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.

Remarketable Subordinated Notes

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

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

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

Dominion has recorded the present value of the stock purchase contract payments as a liability offset by a charge to additional paid-in capital in equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense.

109

Combined Notes to Consolidated Financial Statements, Continued

In calculating diluted EPS, Dominion applies the treasury stock method to the Equity Units. These securities did not have an effect on diluted EPS for the year ended 2013.

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

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

Issuance Date	Units Issued		Total Net Proceeds		Total Long- term Debt		RSN Annual Interest Rate			Stock Purchase Contract Annual Rate			Stock Purchase Contract Liability(1)		Stock Purchase Settlement Date		RSN Maturity Date
(millions, except interest rates)
6/7/2013		11	$	533.5	$	550.0		1.070	%		5.055	%	$	76.7		4/1/2016		4/1/2021
6/7/2013		11	$	553.5	$	550.0		1.180	%		4.820	%	$	79.3		7/1/2016		7/1/2019

(1) Payments of $17 million were made in 2013. The stock purchase contract liability was $139 million at December 31, 2013.

Regulated Natural Gas Financing Plans

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

110

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, 2013 or 2012.

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, 2013 and 2012. 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, 2013:

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		100.00
6.98		600		100.00
Flex Money Market Preferred 12/02, Series A		1,250		100.00	(1)
Total		2,590

(1) Effective March 20, 2011 the rate was reset to 6.12% until March 20, 2014 after which the rate was due to be reset through an auction process. However, in February 2014, Virginia Power provided irrevocable notice to redeem the stock on March 20, 2014 at a price of $100 per share plus accumulated and unpaid dividends.

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. In January 2014, Dominion began purchasing its common stock on the open market for these plans.

During 2013, Dominion issued approximately 5.4 million shares of common stock through various programs. Dominion received cash proceeds of $278 million from the issuance of 4.7 million of such shares through Dominion Direct and employee savings plans.

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 $317 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 2013.

VIRGINIA POWER

In 2013, 2012 and 2011, Virginia Power did not issue any shares of its common stock to Dominion.

Shares Reserved for Issuance

At December 31, 2013, Dominion had approximately 48 million shares reserved and available for issuance for Dominion Direct^®, employee stock awards, employee savings plans, director stock compensation plans, contingent convertible senior notes and issuance in connection with stock purchase contracts. See Note 17 for more information.

Repurchase of Common Stock

Dominion did not repurchase any shares in 2013 or 2012 and does not plan to repurchase shares during 2014, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock and purchases of common stock on the open market in 2014 for direct stock purchase plans, 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,	2013			2012
(millions)
Dominion
Net deferred losses on derivatives-hedging activities, net of tax of $196 and $87	$	(288	)	$	(122	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(307) and $(206)		474			326
Net unrecognized pension and other postretirement benefit costs, net of tax of $365 and $745		(510	)		(1,081	)
Total AOCI	$	(324	)	$	(877	)
Virginia Power
Net deferred losses on derivatives-hedging activities, net of tax of $— and $3	$	—		$	(6	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(30) and $(19)		48			31
Total AOCI	$	48		$	25

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

	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Unrecognized pension and other postretirement benefit costs			Total
(millions)
Year Ended December 31, 2013
Beginning balance	$	(122	)	$	326		$	(1,081	)	$	(877	)
Other comprehensive income before reclassifications: gains (losses)		(243	)		203			516			476
Amounts reclassified from accumulated other comprehensive income (gains) losses(1):		77			(55	)		55			77
Net current period other comprehensive income (loss)		(166	)		148			571			553
Ending balance	$	(288	)	$	474		$	(510	)	$	(324	)

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

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Combined Notes to Consolidated Financial Statements, Continued

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

Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Year Ended December 31, 2013
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	58		Operating revenue
		47		Purchased gas
		10		Electric fuel and other energy-related purchases
Interest rate contracts		15		Interest and related charges
Total		130
Tax		(53	)	Income tax expense
Total, net of tax	$	77
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(98	)	Other income
Impairment		8		Other income
Total		(90	)
Tax		35		Income tax expense
Total, net of tax	$	(55	)
Unrecognized pension and other postretirement benefit costs:
Prior-service costs (credits)	$	(8	)	Other operations and maintenance
Actuarial losses		102		Other operations and maintenance
Total		94
Tax		(39	)	Income tax expense
Total, net of tax	$	55

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

	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on nuclear decommissioning trust funds			Total
(millions)
Year Ended December 31, 2013
Beginning balance	$	(6	)	$	31		$	25
Other comprehensive income before reclassifications: gains (losses)		6			20			26
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)		—			(3	)		(3	)
Net current period other comprehensive income (loss)		6			17			23
Ending balance	$	—		$	48		$	48

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

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

Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Year Ended December 31, 2013
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(6	)	Other income
Impairment		1		Other income
Total		(5	)
Tax		2		Income tax expense
Total, net of tax	$	(3	)

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, 2013, 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 period based on the fair value of the equity or liability instruments issued. Dominion’s results for the years ended December 31, 2013, 2012 and 2011 include $31 million, $25 million, and $39 million, respectively, of compensation costs and $11 million, $8 million, and $13 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, 2013, 2012 and 2011, Dominion realized less than $1 million, $10 million and $2 million, respectively, of excess tax benefits from the vesting of restricted stock awards and exercise of stock options.

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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 and 2011. There were no stock options outstanding in 2013. No options were granted under any plan in 2013, 2012 or 2011.

	Shares			Weighted - average Exercise Price		Weighted - average Remaining Contractual Life	Aggregated Intrinsic Value(1)
	(thousands)			(years)			(millions)
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 any stock option exercises. Dominion received cash proceeds from the exercise of stock options of approximately $19 million, and $38 million in the years ended December 31, 2012 and 2011, respectively.

RESTRICTED STOCK

Restricted stock grants are made to officers under Dominion’s LTIP and may also be granted to certain key non-officer employees from time to time. The fair value of Dominion’s restricted stock awards is equal to the closing 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, 2013, 2012 and 2011:

	Shares			Weighted - average Grant Date Fair Value
	(thousands)
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
Granted		312			54.70
Vested		(356	)		39.00
Cancelled and forfeited		(34	)		51.11
Nonvested at December 31, 2013		1,007		$	49.35

As of December 31, 2013, unrecognized compensation cost related to nonvested restricted stock awards totaled $21 million and is expected to be recognized over a weighted-average period of 1.8 years. The fair value of restricted stock awards that vested was $20 million, $30 million, and $28 million in 2013, 2012 and 2011, 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 2012 and February 2013.

The issuance of awards is based on the achievement of two performance metrics during a two-year period: TSR relative to that of companies listed as members of the Philadelphia 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 closing 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 February 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.

After the performance period for the February 2011 grants ended on December 31, 2012, the CGN Committee determined the actual performance against metrics established for those awards. For awards to officers, 3 thousand shares of the outstanding goal-based stock awards were converted to 2 thousand non-restricted shares and issued to the officers.

113

Combined Notes to Consolidated Financial Statements, Continued

The following table provides a summary of goal-based stock activity for the years ended December 31, 2013, 2012 and 2011:

	Targeted Number of Shares			Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2010		161		$	31.79
Granted		3			43.54
Vested		(20	)		34.62
Cancelled and forfeited		(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
Granted		4			54.17
Vested		(2	)		43.54
Cancelled and forfeited		(1	)		43.54
Nonvested at December 31, 2013		5		$	53.85

At December 31, 2013, the targeted number of shares expected to be issued under the February 2012 and February 2013 awards was approximately 5 thousand. In January 2014, the CGN Committee determined the actual performance against metrics established for the February 2012 awards with a performance period that ended December 31, 2013. Based on that determination, the total number of shares to be issued under the February 2012 goal-based stock awards was approximately 1 thousand.

As of December 31, 2013, 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.

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.

In February 2011, a cash-based performance grant was made to officers. A portion of the grant, representing $6 million was paid in December 2012, based on the achievement of two performance metrics during 2011 and 2012: ROIC and TSR relative to that of a peer group of companies. The total amount of the award under the grant was $8 million and the remaining $2 million of the grant was paid in February 2013.

In February 2012, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $8 million was paid in December 2013, based on the achievement of two performance metrics during 2012 and 2013: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total expected award under the grant is $12 million and the remaining portion of the grant is expected to be paid by

March 15, 2014. At December 31, 2013, a liability of $4 million had been accrued for the remaining portion of the award.

In February 2013, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2015 based on the achievement of two performance metrics during 2013 and 2014: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. At December 31, 2013, the targeted amount of the grant was $13 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, 2013, 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, 2013.

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 and equity units, initially in the form of corporate units.

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 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.

114

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 $959 million in 2013 and $743 million in 2012, versus expected returns of $554 million and $509 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.

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 2013 and 2012. Effective January 1, 2013, Dominion changed 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 reduced other postretirement benefit costs by approximately $20 million annually beginning in 2012. As a result of the adoption of the EGWP, Dominion will begin to receive an increased level of Medicare Part D subsidies, in the form of reduced costs rather than a direct reimbursement, over the next few years.

Dominion remeasured all of its pension and other postretirement benefit plans in the second quarter of 2013. The remeasurement resulted in a reduction in the pension benefit obligation of approximately $354 million and a reduction in the accumulated postretirement benefit obligation of approximately $78 million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by approximately $36 million, excluding the impacts of curtailments. The discount rate used for the remeasurement was 4.80% for the pension plans and 4.70% for the other postretirement benefit plans. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.

In the fourth quarter of 2013, Dominion remeasured its other postretirement benefit plans as a result of a plan amendment that changed medical coverage for certain Medicare-eligible retirees effective April 2014. The remeasurement resulted in a reduction in the accumulated postretirement benefit obligation of approx-

imately $220 million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by approximately $8 million. The amendment is expected to reduce net periodic benefit cost by $40 million to $60 million for each of the next five years. The discount rate used for the remeasurement was 4.80%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.

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,	2013			2012			2013			2012
(millions, except percentages)
Changes in benefit obligation:
Benefit obligation at beginning of year	$	6,125		$	4,981		$	1,719		$	1,493
Service cost		131			116			43			44
Interest cost		271			268			73			79
Benefits paid		(229	)		(208	)		(75	)		(88	)
Actuarial (gains) losses during the year		(650	)		967			(170	)		191
Plan amendments(1)		1			1			(220	)		1
Settlements and curtailments(2)		(24	)		—			(16	)		(6	)
Special termination benefits		—			—			1			—
Medicare Part D reimbursement		—			—			5			5
Benefit obligation at end of year	$	5,625		$	6,125		$	1,360		$	1,719
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	5,553		$	5,145		$	1,156		$	1,042
Actual return on plan assets		781			611			178			132
Employer contributions		8			5			12			16
Benefits paid		(229	)		(208	)		(31	)		(34	)
Fair value of plan assets at end of year	$	6,113		$	5,553		$	1,315		$	1,156
Funded status at end of year	$	488		$	(572	)	$	(45	)	$	(563	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	913		$	701		$	29		$	1
Other current liabilities		(15	)		(2	)		(3	)		(4	)
Noncurrent pension and other postretirement benefit liabilities		(410	)		(1,271	)		(71	)		(560	)
Net amount recognized	$	488		$	(572	)	$	(45	)	$	(563	)
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate(3)		5.20%/ 5.30%			4.40	%		5.00%/ 5.10%			4.40	%
Weighted average rate of increase for compensation		4.21%			4.21	%		4.22%			4.22	%

(1) Relates to a plan amendment that changed medical coverage for certain Medicare-eligible retirees.

115

Combined Notes to Consolidated Financial Statements, Continued

(2) 2013 amounts relate primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor.

(3) Pension rates are 5.20% for the gas union plans and 5.30% for the nonunion and other union plans. OPEB rates are 5.00% for the gas union plans and 5.10% for the nonunion and other union plans.

The ABO for all of Dominion’s defined benefit pension plans was $5.1 billion and $5.5 billion at December 31, 2013 and 2012, 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 2013, Dominion made no contributions to its qualified defined benefit pension plans and no contributions are currently expected in 2014. 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 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 $12 million to the Dominion VEBAs in 2014.

Dominion does not expect any pension or other postretirement plan assets to be returned to the Company during 2014.

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,	2013		2012		2013		2012
(millions)
Benefit obligation	$	4,978	$	5,462	$	1,233	$	1,591
Fair value of plan assets		4,553		4,189		1,158		1,027

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,	2013		2012
(millions)
Accumulated benefit obligation	$	114	$	4,850
Fair value of plan assets		—		4,189

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)
2014	$	264	$	91
2015		269		93
2016		283		96
2017		300		98
2018		319		100
2019-2023		1,868		507

Plan Assets

Dominion’s overall objective for investing its pension and other postretirement plan assets is to achieve appropriate 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. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. 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. Common/collective trust funds are funds of grouped assets that follow various investment strategies. 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.

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The fair values of Dominion’s pension plan assets by asset category are as follows:

	Fair Value Measurements
	Pension Plans
At December 31,	2013								2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	53	$	126		—	$	179	$	—	$	195	$	—	$	195
U.S. equity:
Large Cap		1,220		—		—		1,220		927		104		—		1,031
Other		514		—		—		514		425		99		—		524
Non-U.S. equity:
Large Cap		308		—		—		308		313		68		—		381
Other		391		—		—		391		228		167		—		395
Common/collective trust funds		—		1,387		—		1,387		—		—		—		—
Fixed income:
Corporate debt instruments		43		451		—		494		27		1,026		—		1,053
U.S. Treasury securities and agency debentures		2		229		—		231		331		304		—		635
State and municipal		69		107		—		176		1		71		—		72
Other securities		7		50		—		57		5		43		—		48
Real estate:
REITs		32		—		—		32		29		—		—		29
Partnerships		—		—		227		227		—		—		321		321
Other alternative investments:
Private equity		—		—		530		530		—		—		456		456
Debt		—		—		180		180		—		—		192		192
Hedge funds		—		—		187		187		—		—		221		221
Total	$	2,639	$	2,350	$	1,124	$	6,113	$	2,286	$	2,077	$	1,190	$	5,553

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,	2013								2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	3	$	14	$	—	$	17	$	—	$	13	$	—	$	13
U.S. equity:
Large Cap		472		—		—		472		378		5		—		383
Other		26		—		—		26		21		45		—		66
Non-U.S. equity:
Large Cap		111		—		—		111		93		3		—		96
Other		20		—		—		20		11		8		—		19
Common/collective trust funds		—		502		—		502		—		—		—		—
Fixed income:
Corporate debt instruments		2		23		—		25		1		160		—		161
U.S. Treasury securities and agency debentures		—		12		—		12		16		266		—		282
State and municipal		4		5		—		9		—		9		—		9
Other securities		—		3		—		3		—		2		—		2
Real estate:
REITs		2		—		—		2		1		—		—		1
Partnerships		—		—		19		19		—		—		24		24
Other alternative investments:
Private equity		—		—		60		60		—		—		58		58
Debt		—		—		27		27		—		—		31		31
Hedge funds		—		—		10		10		—		—		11		11
Total	$	640	$	559	$	116	$	1,315	$	521	$	511	$	124	$	1,156

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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
(millions)
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
Actual return on plan assets:
Relating to assets still held at the reporting date		15			98			32			21			166			(2	)		6			3			1			8
Relating to assets sold during the period		(36	)		(48	)		(34	)		(4	)		(122	)		1			3			—			1			5
Purchases		6			115			32			—			153			1			7			2			—			10
Sales		(79	)		(91	)		(42	)		(51	)		(263	)		(5	)		(14	)		(9	)		(3	)		(31	)
Balance at December 31, 2013	$	227		$	530		$	180		$	187		$	1,124		$	19		$	60		$	27		$	10		$	116

Investments in Common/Collective Trust Funds in Dominion’s pension and other postretirement plans are stated at fair value as determined by the issuer of the Common/Collective Trust Funds based on the fair value of the underlying investments. The Common/Collective Trusts do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the Common/Collective Trust Funds have limited withdrawal or redemption rights during the term of the investment. Strategies of the Common/Collective Trust Funds are as follows:

Ÿ Wells Fargo Closed End Bond Trust-The Fund invests in stocks, bonds or a combination of both. Shares of the Fund are traded on a stock exchange and are subject to market risk like stocks, bonds and mutual funds. The Fund may invest in a less liquid portfolio of stocks and bonds because the fund does not need to sell securities to meet shareholder redemptions as mutual funds in order to keep a percentage of its portfolio in cash to pay back investors who withdraw shares.

Ÿ JPMorgan Core Bond Trust-The Fund seeks to maximize total return by investing primarily in a diversified portfolio of intermediate- and long-term debt securities. The Fund invests primarily in investment-grade bonds; it generally maintains an average weighted maturity between four and 12 years. It may shorten its average weighted maturity if deemed appropriate for temporary defensive purposes.

Ÿ SSgA Russell 2000 Value Index Common Trust-The Fund measures the performance of the small-cap value segment of the U.S. equity universe. The Russell 2000 Value Index is constructed to provide a comprehensive and unbiased barometer for the small-cap value segment. The Index is completely reconstituted annually to ensure larger stocks do not

distort the performance and characteristics of the true small-cap opportunity set and that the represented companies continue to reflect value characteristics.

Ÿ SSgA Daily MSCI Emerging Markets Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI Emerging Markets Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company).

Ÿ SSgA Daily MSCI ACWI Ex-USA Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI ACWI Ex-USA Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company).

Ÿ SSgA S&P 400 MidCap Index-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of its benchmark index (the Index) over the long term. The S&P MidCap 400 is comprised of approximately 400 U.S. mid-cap securities and accounts for approximately 7% coverage of the U.S. stock market capitalization. SSgA will typically attempt to invest in the equity securities comprising the Index, in approximately the same proportions as they are represented in the Index.

Ÿ JPMorgan Chase Bank U.S. Active Core Plus Equity Fund-The Fund seeks to outperform the S&P 500 Index (the Benchmark), gross of fees, over a market cycle. The Fund invests primarily in a portfolio of long and short positions in

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equity securities of large and mid capitalization U.S. companies with characteristics similar to those of the Benchmark.

Ÿ Mondrian International Small Cap Equity Fund-The Fund’s investment objective is long-term total return. The Fund

primarily invests in equity securities of non-U.S. small capitalization companies that, in the investment manager’s opinion, are undervalued at the time of purchase based on fundamental value analysis employed by the investment manager.

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,	2013			2012			2011			2013			2012			2011
(millions, except percentages)
Service cost	$	131		$	116		$	108		$	43		$	44		$	48
Interest cost		271			268			258			73			79			94
Expected return on plan assets		(462	)		(430	)		(440	)		(92	)		(79	)		(79	)
Amortization of prior service (credit) cost		3			3			3			(15	)		(13	)		(13	)
Amortization of net actuarial loss		165			132			96			7			6			12
Settlements and curtailments(1)		(2	)		—			—			(15	)		(4	)		1
Special termination benefits		—			—			—			1			—			—
Net periodic benefit cost	$	106		$	89		$	25		$	2		$	33		$	63
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	(968	)	$	786		$	534		$	(255	)	$	139		$	(157	)
Prior service (credit) cost		1			—			—			(215	)		1			(70	)
Settlements and curtailments(1)		(22	)		—			—			(7	)		(2	)		(1	)
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss		(165	)		(132	)		(96	)		(7	)		(6	)		(12	)
Amortization of prior service credit (cost)		(3	)		(3	)		(3	)		15			13			13
Total recognized in other comprehensive income and regulatory assets and liabilities	$	(1,157	)	$	651		$	435		$	(469	)	$	145		$	(227	)
Significant assumptions used to determine periodic cost:
Discount rate		4.40%-4.80	%		5.50	%		5.90	%		4.40%-4.80	%		5.50	%		5.90	%
Expected long-term rate of return on plan assets		8.50	%		8.50	%		8.50	%		7.75	%		7.75	%		7.75	%
Weighted average rate of increase for compensation		4.21	%		4.21	%		4.61	%		4.22	%		4.22	%		4.62	%
Healthcare cost trend rate(2)											7.00	%		7.00	%		7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(2)											4.60	%		4.60	%		4.60	%
Year that the rate reaches the ultimate trend rate(2)											2062			2061			2060

(1) 2013 amount relates primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor.

(2) 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 (credit) cost are as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2013		2012		2013			2012
(millions)
Net actuarial (gain) loss	$	1,709	$	2,865	$	(40	)	$	229
Prior service (credit) cost		10		11		(271	)		(71	)
Total(1)	$	1,719	$	2,876	$	(311	)	$	158

(1) As of December 31, 2013, of the $1.7 billion and $(311) million related to pension benefits and other postretirement benefits, $1.0 billion and $(156) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. 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.

The following table provides the components of AOCI and regulatory assets and liabilities as of December 31, 2013 that are expected to be amortized as components of periodic benefit cost in 2014:

	Pension Benefits		Other Postretirement Benefits
(millions)
Net actuarial loss	$	112	$	2
Prior service (credit) cost		3		(28	)

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;

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Combined Notes to Consolidated Financial Statements, Continued

• 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 net periodic cost for 2014	$	16	$	(18	)
Effect on other postretirement benefit obligation at December 31, 2013		140		(118	)

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 2013, 2012 and 2011, Dominion recognized $40 million, $40 million and $38 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 2013 and 2012, Virginia Power made no contributions to the plan and no contributions are currently expected in 2014. Virginia Power’s net periodic pension cost related to this pension plan was $96 million, $72 million and $50 million in 2013, 2012 and 2011, 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 $5 million, $13 million and $23 million in 2013, 2012 and 2011, 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. During 2013 and 2012, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2014.

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. During 2013, 2012 and 2011, Virginia Power recognized $16 million, $15 million and $14 million, respectively, as employer matching contributions to these plans.

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. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on Dominion’s or Virginia Power’s financial position, liquidity or results of operations.

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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. During the fourth quarter of 2013, Virginia Power recorded charges totaling $26 million ($16 million after-tax) for certain exit activities associated with these coal units, including the cost of employee severance, vendor contract termination, and inventory not expected to be used or usable at other stations.

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 were not material to Dominion. In August 2012, the court vacated CSAPR in its entirety and ordered the EPA to implement CAIR until a valid replacement rule is issued. In October 2012, the EPA filed a peti-

tion requesting a rehearing of the court’s decision, which was denied in January 2013. The mandate vacating CSAPR was issued in February 2013. In March 2013, the EPA and several environmental groups filed petitions with the U.S. Supreme Court requesting review of the decision to vacate and remand CSAPR. In June 2013, the U.S. Supreme Court granted the EPA’s petition seeking review of the D.C. Circuit’s decision that vacated and remanded CSAPR. With respect to Dominion’s generation fleet, the cost to comply with CAIR is not expected to be material. Future outcomes of litigation and/or any additional action to issue a revised rule could affect the assessment regarding cost of compliance.

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

In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerned historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, NSPS, the Title V permit program and the stations’ respective State Implementation Plans. In May 2010, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerned historical operating changes and capital improvements undertaken at Brayton Point.

Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. Dominion entered into settlement discussions with the U.S. government and reached an agreement to settle the allegations. In April 2013, the U.S. government lodged a consent decree and complaint with the U.S. District Court for the Central District of Illinois that resolves all alleged violations at State Line, Kincaid and Brayton Point. The settlement mandates the closure of State Line, installation of certain control technology at Kincaid and Brayton Point, the achievement of certain emissions limitations, payment of a civil penalty of $3 million and funding of $10 million in environmental mitigation projects. In July 2013, the court entered the consent decree, concluding the enforcement action. Dominion previously accrued a liability of $13 million related to this matter. State Line ceased operations in March 2012 and was sold in June 2012. The installation of pollution control technology was in progress at Kincaid and had been completed at Brayton Point. In August 2013, Dominion sold Kincaid and Brayton Point. Under the terms of the sale transaction, Dominion retained the $13 million liability associated with the settlement agreement. Dominion has paid the civil penalty and is implementing the environmental mitigation projects.

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Combined Notes to Consolidated Financial Statements, Continued

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 applicable aspects of the CWA programs at their operating facilities.

In September 2010, Millstone’s NPDES permit was reissued under the CWA. The conditions of the permit require an evaluation of control technologies that could result in additional expenditures in the future. The report summarizing the results 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. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. A remedy has not been selected. Due to the uncertainty surrounding the other sites, Dominion is unable to make an estimate of the potential financial statement impacts.

CLIMATE CHANGE LEGISLATION AND REGULATION

Massachusetts, Rhode Island, Connecticut, and Maryland, among other states, have joined RGGI, a multi-state effort to reduce CO₂ emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO₂ emissions from power plants in participating states are required to be stabilized at current levels from 2009 to 2015. Further reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO₂ emissions. During 2012, RGGI underwent a program review, and in February 2013, revisions to the RGGI model rule were issued that include a reduction of the regional CO₂ emissions cap from 165 million tons to 91 million tons beginning in January 2014, with an additional 2.5% reduction per year through 2020. The revisions also include changes to compliance demonstration requirements for regulated entities, offset and cost containment mechanisms. Most of the RGGI states have completed the regulatory and/or legislative processes required to amend existing state regulations to implement the RGGI program changes. However, as a result of the recent sales of several power plants located in these states, Dominion does not expect that RGGI will have a material effect on operations, financial condition, and/or cash flows.

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 pro-

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gram 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 set national emission standards for new coal, oil, integrated gasification, and combined cycle units larger than 25MW. The proposed rule covered CO₂ only and does not apply to existing sources. The proposed rule also does not apply to any new or existing biomass units. In June 2013, the President of the U.S. released a Climate Action Plan focusing on ways to meet the national GHG reduction goal of 17% from 2005 levels by 2020. Pursuant to the Presidential Memorandum issued in conjunction with the Climate Action Plan, the EPA withdrew the April 2012 proposal and re-proposed the NSPS standards for new sources on January 8, 2014 and is expected to finalize the rule in 2014 or early 2015. The Presidential Memorandum also directed the EPA to propose a rule for reconstructed, modified and existing sources of GHG emissions no later than June 2014, and issue a final rule no later than June 2015, to provide guidelines to the states to achieve the required GHG reductions. Dominion currently cannot predict with certainty the direct or indirect financial impact on operations from these rule revisions, but believes the expenditures to comply with any new requirements could be material.

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

In July 2011, the EPA signed a final rule deferring the need for Prevention of Significant Deterioration and Title V permitting for CO₂ emissions for biomass projects. This rule temporarily deferred for a period of up to 3 years the consideration of CO₂ emissions from biomass projects when determining whether a stationary source meets the Prevention of Significant Deterioration and Title V applicability thresholds, including those for the application of best available control technology. In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the CO₂ deferral period. It is unclear how the court’s decision will affect biomass sources that were permitted during the deferral

period, however the expenditures to comply with any new requirements could be material.

Natrium and Blue Racer

In January 2011, Dominion announced the development of a natural gas processing and fractionation facility in Natrium, West Virginia, and in July 2011 it executed a contract for the construction of the first phase of the facility. The first phase of the project is fully contracted and was placed into service in May 2013. In August 2013, the Natrium natural gas processing and fractionation facility was contributed to the Blue Racer joint venture. In September 2013, the Natrium facility was shut down following a fire at the plant. It returned to service in January 2014. There was no material impact on Dominion’s financial condition, results of operations, and/or cash flows.

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

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Combined Notes to Consolidated Financial Statements, Continued

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

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 2013 calculation for the NRC minimum financial assurance amount, aggregated for Dominion’s and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.8 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 2013 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2013 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 NRC minimum financial assurance requirement, which may include, if needed, 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 $13.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

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

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

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

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

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

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During 2013, Kewaunee ceased power production and commenced decommissioning activities. Effective February 1, 2013, Kewaunee’s accidental outage policy for replacement power costs was canceled.

ODEC, a part owner of North Anna, and Massachusetts Municipal and Green Mountain, 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.

In 2012, Dominion and Virginia Power resolved additional claims for damages incurred at Millstone, Kewaunee, Surry and North Anna with the Authorized Representative of the Attorney General. The Companies entered into settlement agreements that resolved claims for damages incurred through December 31, 2010, and also provide for periodic payments after that date for damages incurred through December 31, 2013. Initial settlement payments in the amounts of $20 million for Millstone, $6 million for Kewaunee and $75 million for Surry and North Anna were received in the fourth quarter of 2012. In the fourth quarter of 2013, Dominion received payment of approximately $5 million for resolution of claims incurred at Millstone for the period January 1, 2011 through June 30, 2012. The government has formally accepted an offer of settlement for resolution of claims incurred at Kewaunee in the amount of approximately $2 million for the period January 1, 2011 through December 31, 2012, and payment is expected in the first quarter of 2014. By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013.

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 $79 million and $36 million at December 31, 2013 and 2012, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $50 million and $26 million at December 31, 2013 and 2012, respectively.

Pursuant to a November 2013 decision of the U.S Court of Appeals for the District of Columbia Circuit, in January 2014 the Secretary of the DOE sent a recommendation to the U.S. Congress to adjust to zero the current fee of $1 per MWh for electricity paid by civilian nuclear power generators for disposal of spent nuclear fuel. The government continues to pursue further judicial review of the November 2013 decision and until such time as the processes specified in the Nuclear Waste Policy Act for adjustment of the fee are completed, civilian nuclear power generators, including the Companies, are required to pay the waste fee. In 2013, Dominion and Virginia Power recognized fees of $44 million and $27 million, respectively.

The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Long-Term Purchase Agreements

At December 31, 2013, 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:

	2014		2015		2016		2017		2018		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	336	$	316	$	253	$	159	$	104	$	163	$	1,331

(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, 2013, the present value of Virginia Power’s total commitment for capacity payments is $1.1 billion. Capacity payments totaled $345 million, $337 million, and $338 million, and energy payments totaled $236 million, $214 million, and $275 million for 2013, 2012 and 2011, 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, 2013 are as follows:

	2014		2015		2016		2017		2018		Thereafter		Total
(millions)
Dominion	$	63	$	60	$	51	$	43	$	37	$	87	$	341
Virginia Power	$	27	$	26	$	21	$	17	$	14	$	27	$	132

Rental expense for Dominion totaled $101 million, $112 million, and $155 million for 2013, 2012 and 2011, respectively. Rental expense for Virginia Power totaled $42 million, $48 million, and $50 million for 2013, 2012, and 2011, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.

Guarantees, Surety Bonds and Letters of Credit

DOMINION

At December 31, 2013, Dominion had issued $69 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2013, Dominion’s exposure under these guarantees was $39 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, 2013, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $90 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 com-

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Combined Notes to Consolidated Financial Statements, Continued

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

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	27	$	27
Commodity transactions(3)		3,158		403
Nuclear obligations(4)		232		68
Cove Point(5)		335		—
Other(6)		669		108
Total	$	4,421	$	606

(1) Represents the estimated portion of the guarantee’s stated limit that is utilized as of December 31, 2013 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount.

(2) Guarantee of debt of a DEI subsidiary. In the event of default by the subsidiary, Dominion would be obligated to repay such amounts.

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

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

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

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

Additionally, as of December 31, 2013 Dominion had purchased $147 million of surety bonds and authorized the issuance of letters of credit by financial institutions of $11 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, 2013, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. Virginia Power had also purchased $59 million of surety bonds for various purposes, including providing workers’ compensation coverage, and authorized the issuance of letters of credit by financial institutions of $1 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, 2013, 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.

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, 2013 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,

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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 any collateral. At December 31, 2013, Dominion’s credit exposure totaled $263 million. Of this amount, investment grade counterparties, including those internally rated, represented 63%. No counterparty exposure exceeded 6% of Dominion’s total exposure.

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, 2013, 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, 2013 and 2012, Dominion would have been required to post an additional $146 million and $110 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 $76 million in collateral at December 31, 2013 and $4 million in collateral at December 31, 2012, 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, 2013 and 2012 was $169 million and $163 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power were not material as of December 31, 2013 and 2012. 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, 2013 and 2012, Virginia Power’s derivative liabilities with affiliates were not material.

DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. 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,	2013		2012		2011
(millions)
Commodity purchases from affiliates	$	417	$	368	$	376
Services provided by affiliates		415		399		393
Services provided to affiliates		21		19		21

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 $97 million and $243 million in short-term demand note borrowings from Dominion as of December 31, 2013 and 2012, respectively. Virginia Power’s outstanding borrowings, net of repayments, under the Dominion money pool for its nonregulated subsidiaries totaled $192 million as of December 31, 2012. There were no borrowings as of December 31, 2013. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the years ended December 31, 2013, 2012 and 2011.

There were no issuances of Virginia Power’s common stock to Dominion in 2013, 2012 or 2011.

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Combined Notes to Consolidated Financial Statements, Continued

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
Dominion Generation	Regulated electric fleet	X	X
	Merchant electric fleet	X
	Nonregulated retail energy marketing (electric and gas)(1)	X
Dominion Energy	Gas transmission and storage	X
	Gas distribution and storage	X
	LNG services	X
	Producer services	X

(1) As a result of Dominion’s decision to realign its business units effective for 2013 year-end reporting, nonregulated retail energy marketing operations were moved from DVP to the Dominion Generation segment.

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 operations that are 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.

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

DOMINION

In 2013, Dominion reported after-tax net expense of $452 million in the Corporate and Other segment, with $184 million of these net expenses attributable to specific items related to its operating segments.

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

Ÿ A $135 million ($92 million after-tax) net loss from discontinued operations of Brayton Point and Kincaid, including debt extinguishment of $64 million ($38 million after-tax) related to the sale, impairment charges of $48 million ($28

million after-tax), a $17 million ($18 million after-tax) loss on the sale which includes a $16 million write-off of goodwill, and a $6 million ($8 million after-tax) loss from operations, attributable to Dominion Generation; and

Ÿ A $182 million ($109 million after-tax) net loss, including a $55 million ($33 million after-tax) impairment charge related to certain natural gas infrastructure assets and a $127 million ($76 million after-tax) loss related to the producer services business discussed above, attributable to Dominion Energy; partially offset by

Ÿ An $81 million ($49 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.

In 2012, Dominion reported after-tax net expense of $1.7 billion in the Corporate and Other segment, with $1.5 billion of these net expenses attributable to specific items related 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 discontinued operations, including impairment charges, of Brayton Point and Kincaid, which were sold in 2013, attributable to Dominion Generation;

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 $607 million for specific items in the Corporate and Other segment, with $364 million of these net expenses attributable to specific items related 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 ($33 million after-tax) net loss from discontinued operations of Brayton Point and Kincaid, which were sold in 2013, attributable to Dominion Generation;

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; and

128

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.

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

Year Ended December 31,	DVP(1)		Dominion Generation(1)(2)			Dominion Energy		Corporate and Other(2)			Adjustments & Eliminations(1)			Consolidated Total
(millions)
2013
Total revenue from external customers	$	1,825	$	8,445		$	1,783	$	3		$	1,064		$	13,120
Intersegment revenue		9		68			1,063		609			(1,749	)		—
Total operating revenue		1,834		8,513			2,846		612			(685	)		13,120
Depreciation, depletion and amortization		427		518			228		35			—			1,208
Equity in earnings of equity method investees		—		(14	)		21		7			—			14
Interest income		—		66			12		42			(66	)		54
Interest and related charges		175		220			26		522			(66	)		877
Income taxes		287		483			409		(287	)		—			892
Loss from discontinued operations, net of tax		—		—			—		(92	)		—			(92	)
Net income (loss) attributable to Dominion		475		1,031			643		(452	)		—			1,697
Investment in equity method investees		—		280			615		21			—			916
Capital expenditures		1,361		1,605			1,043		95			—			4,104
Total assets (billions)		11.9		22.0			12.1		8.5			(4.4	)		50.1
2012
Total revenue from external customers	$	1,846	$	8,170		$	1,813	$	155		$	851		$	12,835
Intersegment revenue		9		104			930		608			(1,651	)		—
Total operating revenue		1,855		8,274			2,743		763			(800	)		12,835
Depreciation, depletion and amortization		392		483			216		36			—			1,127
Equity in earnings of equity method investees		—		3			23		(1	)		—			25
Interest income		1		65			30		71			(106	)		61
Interest and related charges		187		177			47		511			(106	)		816
Income taxes		278		576			352		(395	)		—			811
Loss from discontinued operations, net of tax		—		—			—		(1,125	)		—			(1,125	)
Net income (loss) attributable to Dominion		439		1,021			551		(1,709	)		—			302
Investment in equity method investees		—		414			141		3			—			558
Capital expenditures		1,158		1,615			1,350		22			—			4,145
Total assets (billions)		11.5		21.8			11.2		12.6			(10.3	)		46.8
2011
Total revenue from external customers	$	1,791	$	8,759		$	2,044	$	56		$	1,115		$	13,765
Intersegment revenue		63		123			1,077		595			(1,858	)		—
Total operating revenue		1,854		8,882			3,121		651			(743	)		13,765
Depreciation, depletion and amortization		369		413			207		29			—			1,018
Equity in earnings of equity method investees		—		3			23		9			—			35
Interest income		10		65			27		71			(106	)		67
Interest and related charges		183		148			57		514			(106	)		796
Income taxes		264		655			323		(464	)		—			778
Loss from discontinued operations, net of tax		—		—			—		(58	)		—			(58	)
Net income (loss) attributable to Dominion		416		1,078			521		(607	)		—			1,408
Capital expenditures		1,091		1,593			907		61			—			3,652

(1) Amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

(2) Segment information for 2012 and 2011 has been recast to reflect Brayton Point and Kincaid as discontinued operations, as discussed in Note 3.

At December 31, 2013, 2012, and 2011, 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 2013, Virginia Power reported after-tax net expenses of $47 million for specific items attributable to its operating segments in the Corporate and Other segment.

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

Ÿ A $40 million ($28 million after-tax) charge in connection with the 2013 Biennial Review Order, attributable to Dominion Generation.

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.

129

Combined Notes to Consolidated Financial Statements, Continued

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 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.

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)
2013
Operating revenue	$	1,826	$	5,475	$	(6	)	$	—		$	7,295
Depreciation and amortization		427		425		1			—			853
Interest income		—		6		—			—			6
Interest and related charges		175		192		2			—			369
Income taxes		286		399		(26	)		—			659
Net income (loss)		483		702		(47	)		—			1,138
Capital expenditures		1,360		1,173		—			—			2,533
Total assets (billions)		12.0		15.1		—			(0.1	)		27.0
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

130

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, 2013 and 2012 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		Second Quarter			Third Quarter			Fourth Quarter		Full Year
(millions, except per share amounts)
2013
Operating revenue	$	3,523	$	2,980		$	3,432		$	3,185	$	13,120
Income from operations		930		548			1,034			804		3,316
Net income including noncontrolling interests		502		208			575			435		1,720
Income from continuing operations(1)		494		272			592			431		1,789
Income (loss) from discontinued operations(1)		1		(70	)		(23	)		—		(92	)
Net income attributable to Dominion		495		202			569			431		1,697
Basic EPS:
Income from continuing operations(1)		0.86		0.47			1.02			0.74		3.09
Income (loss) from discontinued operations(1)		—		(0.12	)		(0.04	)		—		(0.16	)
Net income attributable to Dominion		0.86		0.35			0.98			0.74		2.93
Diluted EPS:
Income from continuing operations(1)		0.86		0.47			1.02			0.74		3.09
Income (loss) from discontinued operations(1)		—		(0.12	)		(0.04	)		—		(0.16	)
Net income attributable to Dominion		0.86		0.35			0.98			0.74		2.93
Dividends declared per share		0.5625		0.5625			0.5625			0.5625		2.25
Common stock prices (intraday high-low)	$	58.25 - 51.92	$	61.85 - 53.79		$	64.04 - 55.51		$	67.97 - 61.36	$	67.97 - 51.92

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter(2)			Full Year
2012
Operating revenue	$	3,397		$	3,005		$	3,332		$	3,101		$	12,835
Income from operations		918			628			551			761			2,858
Net income (loss) including noncontrolling interests		501			265			215			(652	)		329
Income from continuing operations(1)		504			290			261			372			1,427
Income (loss) from discontinued operations(1)		(10	)		(32	)		(52	)		(1,031	)		(1,125	)
Net income attributable to Dominion		494			258			209			(659	)		302
Basic EPS:
Income from continuing operations(1)		0.88			0.51			0.45			0.65			2.49
Loss from discontinued operations(1)		(0.02	)		(0.06	)		(0.09	)		(1.80	)		(1.96	)
Net income (loss) attributable to Dominion		0.86			0.45			0.36			(1.15	)		0.53
Diluted EPS:
Income from continuing operations(1)		0.88			0.51			0.45			0.64			2.49
Loss from discontinued operations(1)		(0.02	)		(0.06	)		(0.09	)		(1.79	)		(1.96	)
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

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

(2) Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3.

Dominion’s 2013 results include the impact of the following significant items:

Ÿ Second quarter results include a $70 million after-tax net loss from discontinued operations of Brayton Point and Kincaid; and a $57 million after-tax net loss, including a $33 million after-tax impairment charge related to certain natural gas infrastructure assets and a $24 million after-tax loss related to the producer services business.

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.

131

Combined Notes to Consolidated Financial Statements, Continued

VIRGINIA POWER

Virginia Power’s quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
(millions)
2013
Operating revenue	$	1,781	$	1,710	$	2,059	$	1,745	$	7,295
Income from operations		530		463		679		408		2,080
Net income		287		265		387		199		1,138
Balance available for common stock		283		261		383		194		1,121
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

Virginia Power’s 2013 results include the impact of the following significant item:

Ÿ Fourth quarter results include a $28 million after-tax charge resulting from impacts of the 2013 Biennial Review Order.

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.

132

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 2013 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, 2013, 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, 2013. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control—Integrated Framework (1992) 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, 2013.

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, 2014

133

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, 2013, based on criteria established in Internal Control—Integrated Framework (1992) 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, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) 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, 2013 of Dominion and our report dated February 27, 2014 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2014

134

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 2013 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, 2013, 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, 2013. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control—Integrated Framework (1992) 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, 2013.

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, 2014

135

Item 9B. Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

DOMINION

The following information for Dominion is incorporated by reference from the Dominion 2014 Proxy Statement, which will be filed on or around March 21, 2014:

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 (59)	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 18 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 (56)	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
Mark O. Webb (49)	Vice President, General Counsel and Chief Risk Officer of Virginia Power and Dominion from January 2014 to date; Vice President and General Counsel of Virginia Power and Dominion from January 2013 to December 2013; Deputy General Counsel of DRS from July 2011 to December 2012; Director – Policy & Business Evaluation AES of DRS from May 2009 to June 2011 and Deputy General Counsel of DRS from April 2004 to April 2009. Mr. Webb’s qualifications to serve as a director include his more than 20 years of legal expertise as a practicing attorney with private firms and having served as General Counsel and Deputy General Counsel for Dominion advising on a wide range of matters including securities and corporate finance, mergers and acquisitions, electric and gas regulation, alternative energy policy and litigation. He also has community service and public interest involvement, including serving on non-profit foundations and boards.		2014

(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.

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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 (59)	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 (56)	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 (54)	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 (59)	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 (56)	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.
Robert M. Blue (46)	President of Virginia Power from January 2014 to date; Senior Vice President-Law, Public Policy and Environment of Virginia Power and Dominion from January 2011 to December 2013; 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.
Ashwini Sawhney (64)	Vice President, Controller and CAO of Virginia Power and Dominion from January 2014 to date; Vice President-Accounting of Virginia Power from April 2006 to December 2013; Vice President-Accounting and Controller (CAO) of Dominion from May 2010 to December 2013; 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.
Mark O. Webb (49)	Vice President, General Counsel and Chief Risk Officer of Virginia Power and Dominion from January 2014 to date; Vice President and General Counsel of Virginia Power and Dominion from January 2013 to December 2013; Deputy General Counsel of DRS from July 2011 to December 2012; Director—Policy & Business Evaluation AES of DRS from May 2009 to June 2011 and Deputy General Counsel of DRS from April 2004 to April 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, 2013, 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 Mark O. Webb are “audit committee financial experts” as defined by the SEC. As executive officers of Virginia Power and Dominion, Thomas F. Farrell II, Mark F. McGettrick and Mark O. Webb 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 (http://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 (800) 552-4034. 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 2014 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, 2013.

Robert S. Jepson, Jr., Chairman

William P. Barr

John W. Harris

Mark J. Kington

David A. Wollard

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INTRODUCTION

Virginia Power is a wholly-owned subsidiary of Dominion. Virginia Power’s Board is comprised of Messrs. Farrell, McGettrick and Webb. As executive officers of Virginia Power and Dominion, Messrs. Farrell, McGettrick and Webb are 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 the CGN Committee’s 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 explains the objectives and principles of 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 2013, Virginia Power’s NEOs were:

Ÿ Thomas F. Farrell II, Chairman and CEO;

Ÿ Mark F. McGettrick, Executive Vice President and CFO;

Ÿ David A. Christian, President and COO (Dominion Generation);

Ÿ Paul D. Koonce, President and COO (DVP); and

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 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. 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 2014 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’s 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 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 Dominion’s peer companies’ performance.

Dominion’s 2013 performance indicates that the design of Dominion’s compensation program is meeting these objectives. The NEOs have service with Dominion ranging from 15 to 37 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’s shareholders voted on an advisory basis on its executive compensation program (also known as Say on Pay) and approved it with a 96% vote at the 2013 Annual Meeting, which followed an approval by a 95% vote in 2012. The CGN Committee considered the very strong shareholder endorsement of Dominion’s executive compensation program in continuing the pay-for-performance program that is currently in place without any specific changes based on the vote. Unless Dominion’s 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 to approve Dominion’s executive compensation program. 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 the 2017 Annual Meeting of Shareholders.

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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 CGN Committee’s independent compensation consultants. 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 executive officer share ownership guidelines and compliance, and establishes compensation programs designed to achieve Dominion’s objectives.

THE ROLE OF THE INDEPENDENT COMPENSATION CONSULTANT

In June 2013, the CGN Committee retained Cook & Co. as its independent compensation consultant to advise the Committee on executive and director compensation matters. The CGN Committee’s consultant:

Ÿ Attends meetings as requested by the CGN Committee, either in person or by teleconference;

Ÿ Communicates directly with the chairman of the CGN Committee outside of the CGN Committee meetings as needed;

Ÿ Participates in CGN Committee executive sessions without the CEO present to discuss CEO compensation and any other relevant matters, including the appropriate relationship between pay and performance and emerging trends;

Ÿ Reviews and comments on proposals and materials prepared by management and answers technical questions, as requested; and

Ÿ Generally reviews and offers advice as requested by or on behalf of the CGN Committee regarding other aspects of Dominion’s executive compensation program, including best practices and other matters.

Prior to the engagement of Cook & Co., PM&P served as the independent compensation consultant to the CGN Committee. During 2013, the CGN Committee reviewed and assessed the independence of both PM&P and Cook & Co. and concluded that neither PM&P’s nor Cook & Co.’s work raised any conflicts of interest. Cook & Co. did not provide any additional services to Dominion during 2013, and for the period in 2013 for which PM&P served as the CGN Committee’s independent consultant, PM&P also did not provide any additional services to Dominion.

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 Dominion’s management, 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. Dominion’s management, along with the internal compensation and financial specialists, assist in the design of the incentive com-

pensation plans, including performance target recommendations consistent with the strategic goals of the company, and recommendations for establishing the peer group. Dominion’s 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 the other 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 advice 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 purposes. The Compensation Peer Group is used to assess the competitiveness of the compensation of the NEOs. A separate Performance Grant Peer Group is used to evaluate the relative performance of Dominion for purposes of the LTIP. (See 2013 Performance Grants and Performance Grant Peer Group for additional information.)

In the fall of each year, the CGN Committee reviews and approves the Compensation Peer Group of companies. In selecting the Compensation Peer Group, Dominion uses a methodology that identifies companies in its 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 or 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 Compensation Peer Group for 2013. Dominion’s Compensation Peer Group for 2013 was comprised of the following companies:

Ameren Corporation American Electric Power Company, Inc. CMS Energy Corporation DTE Energy Company Duke Energy Corporation Entergy Corporation Exelon Corporation FirstEnergy Corp. NextEra Energy, Inc. NiSource Inc. PPL Corporation Public Service Enterprise Group Incorporated The Southern Company Xcel Energy Inc.

The CGN Committee and management use the Compensation Peer Group to: (i) compare Dominion’s stock and financial performance against these 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

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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 size compared with the median of the Compensation Peer Group and the complexity of its business.

SURVEY AND OTHER DATA

Dominion does not benchmark or otherwise use broad-based market data as the basis for compensation decisions for the NEOs. Survey compensation data and information on local companies with whom Dominion competes for talent and other companies with comparable market capitalization to Dominion are 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 this 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 the company;

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: (i) the balance of the overall program design, including the mix of cash and equity compensation; (ii) the mix of fixed and

variable compensation; (iii) the balance of short-term and long-term objectives of incentive compensation; (iv) the performance metrics, performance targets, threshold performance requirements and capped payouts related to incentive compensation; (v) the clawback provision on incentive compensation; (vi) Dominion’s share ownership guidelines, including share ownership levels and retention practices and prohibitions on hedging, pledging, and other derivative transactions related to Dominion stock; (vii) the CGN Committee’s ability to exercise negative discretion to reduce the amount of the annual incentive award; and (viii) 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 demonstrating 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 compensation program results in appropriate pay relationships as compared to Dominion’s peer companies and internally among the 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.

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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 50/50 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 returns on invested capital
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 for each NEO that are not given any specific weighting in setting each element of compensation, 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 compensation (base salary plus target AIP award) and total direct compensation (base salary plus target AIP award plus target

long-term incentive award) against data from the Compensation Peer Group to ensure the compensation levels are appropriately competitive. It does not, however, 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, due to insufficient peer group data reported at the time in order to evaluate the competitiveness of his compensation levels. See Exhibit 99.1 for a listing of the companies included in the survey. As part of this analysis, the CGN Committee also takes into account Dominion’s size, including market capitalization and price to earnings ratio, and complexity compared to the companies in the Compensation Peer Group, as well as the tenure of the NEO as compared to executives in a similar position in a Compensation Peer Group Company.

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 the 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 the company (as compared to the other NEOs who are responsible for significant but distinct areas within Dominion) and his overall responsibility for corpo-

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rate 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, in addition to the other factors listed above, for CGN Committee consideration of year-to-year trends and comparisons with peers. The CGN Committee did not make any adjustments to the compensation of any NEOs based on this review for 2013.

Allocation of Total Direct Compensation in 2013

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. Approximately 88% of Mr. Farrell’s targeted 2013 total direct compensation is performance-based, tied to pre-approved performance metrics, including relative TSR and ROIC, or tied to the performance of Dominion stock. For the other NEOs, performance-based and stock-based compensation ranges from 67% to 81% of targeted 2013 total direct compensation. This compares to an average of approximately 55% of targeted compensation at risk for most of 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 targeted total direct compensation opportunities in 2013 for Mr. Farrell and the average of the other NEOs as a group and the allocation of such compensation among base salary, targeted 2013 AIP award and targeted 2013 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. Base salary may be adjusted, as appropriate, to keep salaries in line and competitive with the Compensation Peer Group and to reflect changes in responsibility, including promotions. Base salary adjustments are also 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 the Compensation Peer Group median in 2013 in terms of market capitalization and at median for revenues and assets, 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.

The CGN Committee approved a modest base salary increase for most officers, including a 3.0% base salary increase for Messrs. Farrell, Christian, Koonce and Heacock and a 5.0% base salary increase for Mr. McGettrick effective March 1, 2013. In determining the base salary increase for Mr. McGettrick, the CGN Committee took into consideration Mr. McGettrick’s overall performance, the broader scope of his responsibilities in comparison to the business unit CEOs and his role in developing financing strategies to support Dominion’s long-term growth plan. 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 Dominion Energy business unit reporting to him in addition to the DVP business unit.

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, diversity and other operating and stewardship goal successes;

Ÿ Emphasize teamwork by focusing on common goals;

Ÿ Appropriately balance risk and reward; and

Ÿ Provide a competitive total compensation opportunity.

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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) generally 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 are 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 2013. AIP target award levels are also consistent with the intent to have a significant portion of NEO compensation at risk. There were no changes to the AIP targets from 2012 as a percentage of salary for any NEO for 2013.

Name	2013 AIP Target Award*
Thomas F. Farrell II		125%
Mark F. McGettrick		100%
David A. Christian		90%
Paul D. Koonce		90%
David A. Heacock		70%

*As a % of base salary

FUNDING OF THE 2013 AIP

Funding of the 2013 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 2013 AIP, the CGN Committee established a full funding target at 100% for the NEOs of operating earnings per share between $3.05 and $3.35, inclusive of funding for all plan participants. The maximum funding target of 200% was set at $3.50 operating earnings per share, and no funding if operating earnings were less than $3.00 per share (threshold), with the CGN Committee retaining negative discretion to determine the final funding level for the NEOs. 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%, the NEOs 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, 2013 were $1.88 billion or $3.25 per share which met the target goal for 100% funding.* Consolidated reported earnings in accordance with GAAP for the year ended December 31, 2013, were $1.70 billion or $2.93 per share.

*Reconciliation of 2013 Consolidated Operating Earnings to Reported Earnings. The following items, which are net of tax, are included in Dominion’s 2013 reported earnings, but are excluded from consolidated operating earnings: $92 million net loss from discontinued operations of two merchant power stations (Brayton Point & Kincaid) which were sold in third quarter 2013; $109 million net charge related to an impairment of certain natural gas infrastructure assets and the repositioning of Producer Services; $28 million charge in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2011-2012 test years; $17 million charge associated with Dominion’s operating expense reduction initiative, primarily severance pay and other employee-related costs; $49 million net gain related to Dominion’s investments in nuclear decommissioning trust funds; $30 million benefit due to a downward revision in the nuclear decommissioning AROs for certain merchant nuclear units that are no longer in service; and $17 million net expense related to other items.

HOW AIP PAYOUTS ARE DETERMINED

For the NEOs, payout of funded AIP awards is contingent solely on the achievement of the consolidated operating financial funding goal with the CGN Committee retaining negative discretion to lower the earned payout as it deems appropriate, taking into consideration the accomplishment of the discretionary consolidated financial, business unit financial and operating and stewardship goals, including safety and diversity goals. The percentage allocated to each category of discretionary 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%.

The consolidated operating financial goal is the same as the funding goal and, as noted, was fully achieved for the 2013 AIP. 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 of the NEOs which may be considered by the CGN Committee to reduce the NEOs’ final payout are described under 2013 AIP Payouts and the weightings applied to those goals are shown in the table below.

	Consolidated Financial Goal		Business Unit  Financial Goals		Operating and Stewardship Goals*
					Safety		Diversity		Other
Thomas F. Farrell II		90%		—		5%		5%		—
Mark F. McGettrick		90%		—		5%		5%		—
David A. Christian		45%		45%		5%		5%		—
Paul D. Koonce		45%		45%		5%		5%		—
David A. Heacock		20%		45%		5%		5%		25%

*5% goal weighting for safety and diversity goals. Mr. Heacock had other non-safety/non-diversity operating & stewardship goals as described below.

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2013 AIP PAYOUTS

The formula for calculating an award is:

Dominion’s operating earnings per share for the year ended December 31, 2013 was $3.25, which met the target AIP payout goal for NEOs of achievement of consolidated operating earnings between $3.05 and $3.35 per share for the year ended December 31, 2013. The CGN Committee approved a payout score of 100% for Messrs. Farrell, McGettrick, Christian and Heacock and exercised negative discretion to reduce Mr. Koonce’s payout score to 99.97% for a missed safety goal at DVP which is discussed below. As noted above, the payouts for the NEOs are based solely on the accomplishment of the consolidated operating financial funding goal. The achievement of these discretionary goals are applied only to the extent the CGN Committee deems it appropriate to take these goals in consideration in its exercise of negative discretion to reduce the final payout of the NEOs.

The CGN Committee assessed the business challenges that Dominion faced during 2013 and recognized that all of the business units remained focused on safe and excellent operations and that many of these challenges were nearly overcome. Although all of the business units did not reach their financial targets, the consolidated financial funding and payout goal was achieved and, as such, payouts for the applicable NEOs were not reduced for the business unit financial accomplishments, which are shown below:

Business Unit	Goal Threshold (Net Income)		Goal 100% Payout (Net Income)		Actual 2013 Net Income
(Millions/$)
DVP	$	480	$	600	$	543
Dominion Generation		794		993		963

With respect to Messrs. Farrell and McGettrick, the DRS business unit met its safety goal of four or fewer OSHA recordable incidents with an incidence rate of 0.15 or less. The Dominion Generation business unit, of which Mr. Christian is a part, met its target safety goal of an OSHA incidence rate ranging from 0.27 to 1.23 for certain operating units and recordable incidents of one or fewer for another operating unit within Dominion Generation. Mr. Koonce is part of the DVP and Dominion Energy business units. DVP fell short of the target OSHA incidence rate of 1.21 with an actual rate of 1.22, but the OSHA incidence rate of 1.59 for the Dominion Energy business unit was met. DVP and Dominion Energy met the lost time/restricted duty rates of 0.30 and 0.58, respectively. Mr. Heacock carried a safety goal for the nuclear fleet of 14 or fewer total fleet wide OSHA recordable incidents, which was met.

Each of the NEOs met his discretionary diversity goal relating to one or more of the following areas: talent review, internship program improvements, recruitment and retention process improvements, and workforce training. In addition to safety and diversity goals, Mr. Heacock met his additional discretionary operating and stewardship goals in the following four categories: nuclear safety (based on fleet wide total number of station event-free day clock resets); total online radiation exposure for the fleet; fleet capacity factor percentage and environmental compliance (based on the number of environmental performance points assessed at the nuclear stations).

Amounts earned under the 2013 AIP for each NEO 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 %			2013 AIP Payout
Thomas F. Farrell II	$	435,721	X		125%	X		100%	X		100%	=	$	544,651
Mark F. McGettrick		352,623	X		100%	X		100%	X		100%	=		352,623
David A. Christian		376,964	X		90%	X		100%	X		100%	=		339,268
Paul D. Koonce		238,903	X		90%	X		100%	X		99.97%	=		214,948
David A. Heacock		236,918	X		70%	X		100%	X		100%	=		165,843

*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.

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Mr. Koonce’s payout score was 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

Paul D. Koonce

100%

X

45%

+

100%

X

45%

+

99.7%

X

10%

=

99.97%

Long-Term Incentive Program

OVERVIEW

Dominion’s LTIP is designed to focus on Dominion’s longer-term strategic goals and the retention of its executives. Each long-term incentive award consists of two components: 50% of the award is a full value equity award in the form of restricted stock with time-based vesting and the other 50% is a performance-based cash award. 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. The performance-based award encourages and rewards officers for making decisions and investments that create and maintain long-term shareholder value and benefit Dominion’s 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 2013 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 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 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 direct compensation opportunity. However, as discussed above, long-term incentive target award levels were 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 2013.

As part of the CGN Committee’s review of Dominion’s LTIP, the target 2013 long-term incentive award was increased for generally all officers, including each of the NEOs. This was the first general increase in target awards since the LTIP began in 2006. The increased target award levels reflected the CGN

Committee’s continued desire to place a significant portion of the NEO’s pay at risk, provide total direct compensation that is competitive, and place ongoing focus on achieving Dominion’s long-term growth plan as discussed further below.

The CGN Committee strongly believes in pay for performance and recognizes that Dominion’s continued strong absolute and relative TSR is due substantially in part to the contributions of senior management under the leadership of Dominion’s CEO, Mr. Farrell. In determining the target long-term incentive awards for each of the NEOs, the CGN Committee took into consideration, among many factors, the continued superior performance by each of the NEOs, industry competitiveness for personnel (especially personnel with nuclear expertise), the NEO’s tenure with the company and in his current position and the scope of the NEO’s responsibilities.

The CGN Committee also considered the need for continued focus by the NEOs on Dominion’s long-term growth plan which involves all of the business units of the company and is expected to include approximately $14 billion in investment from 2014 to 2018 to grow its energy infrastructure. In addition, in determining Mr. Farrell’s target long-term incentive award, the CGN Committee also considered Mr. Farrell’s experience as CEO, Dominion’s strong performance under his leadership, the successful advancement of Dominion’s long-term initiatives, the complexity of Dominion’s business, and other factors.

As a result of these considerations, the CGN Committee approved the following target long-term incentive awards for the NEOs for 2013:

Name	2013 Performance Grant		2013 Restricted Stock Grant		2013 Total Target Long-Term Incentive Award		2012 Total Target Long-Term Incentive Award
Thomas F. Farrell II	$	1,350,300	$	1,350,300	$	2,700,600	$	2,250,500
Mark F. McGettrick		573,973		573,973		1,147,946		1,043,588
David A. Christian		439,218		439,218		878,435		798,578
Paul D. Koonce		293,759		293,759		587,518		513,953
David A. Heacock		156,300		156,300		312,600		260,500

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.

Information regarding the fair value of the 2013 restricted stock grants and target cash performance grants for the NEOs is provided in the Grants of Plan-Based Awards table.

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2013 RESTRICTED STOCK GRANTS

All officers received a restricted stock grant on February 1, 2013 based on the stated dollar value above. 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, 2013. The grants have a three-year vesting term, with cliff vesting at the end of the restricted period on February 1, 2016. Dividends are paid to officers during the restricted period. The grant date fair value and vesting terms of the 2013 restricted stock grant awards made to the NEOs are disclosed in the Grants of Plan-Based Awards table and related footnotes.

2013 PERFORMANCE GRANTS

In January 2013, the CGN Committee approved cash performance grants for the NEOs, effective February 1, 2013. The performance period commenced on January 1, 2013 and will end on December 31, 2014. The 2013 performance grants are denominated as a target award, with potential payouts ranging from 0% to 200% of the target based on Dominion’s TSR relative to the Philadelphia Utility Index and ROIC, weighted equally. (See Performance Grant Peer Group for additional information on the Philadelphia Utility Index.)

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 the Performance Grant Peer Group. 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 the 2013 performance grants made to the NEOs are disclosed in the Grants of Plan-Based Awards table and related footnotes.

PERFORMANCE GRANT PEER GROUP

The CGN Committee approved measuring TSR performance for the 2013 performance grants against the TSR of the companies listed as members of the Philadelphia Utility Index at the end of the performance period (the Performance Grant Peer Group). In selecting the Philadelphia Utility Index, the CGN Committee took into consideration that the companies represented in the Philadelphia 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 companies in the Philadelphia Utility Index at the grant date of the 2013 performance grants were as follows:

The AES Corporation Ameren Corporation American Electric Power Company, Inc. CenterPoint Energy, Inc. Consolidated Edison, Inc. Covanta Holding Corporation El Paso Electric Company Entergy Corporation Exelon Corporation FirstEnergy Corp. NextEra Energy, Inc. Northeast Utilities PG&E Corporation

DTE Energy Company Duke Energy Corporation Edison International Public Service Enterprise Group Incorporated The Southern Company Xcel Energy Inc.

PAYOUT UNDER 2012 PERFORMANCE GRANTS

In February 2014, final payouts were made to officers who received cash performance grants in February 2012, including the NEOs. The 2012 performance grants were based on two goals: TSR for the two-year period ended December 31, 2013 relative to the companies in the Philadelphia Utility Index as of the end of the performance period (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 Philadelphia Utility Index as of the end of the same two-year period. The relative TSR targets and corresponding payout scores for the 2012 performance grant were as follows:

Relative TSR Performance Percentile Ranking	Percentage Payout of TSR Percentage*
85th or above		200%
50th		100%
25th		50%
Below 25th		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 2012-2013 period was in the 84^th percentile which produced a payout of 197.7%. Dominion’s TSR for the two-year period ended December 31, 2013 was 32.0%.

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 of Directors. 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 2012 ROIC goals to provide 100% payout if it achieved an ROIC between 7.44% and 7.62% over the two-year performance period. The ROIC performance targets and corresponding payout scores for the 2012 performance grant were as follows:

ROIC Performance	Percentage Payout of ROIC Component*
7.80% and above		200%
7.44% – 7.62%		100%
7.26%		50%
Below 7.26%		0%

* ROIC percentage payout is interpolated between the top and bottom of the percentages for any range.

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Actual ROIC performance for the 2012-2013 period was 7.25%, which was below the threshold and resulted in no payout for the ROIC component of the award.

Based on the achievement of the TSR and ROIC performance goals, the CGN Committee approved a 98.9% payout for the 2012 performance grants. The following table summarizes the achievement of the 2012 performance goals:

Measure	Goal Weight%			Goal Achievement%			Payout%
Relative TSR		50%	X		197.7%	=		98.9%
ROIC		50%	X		0.0%	=		0.0%
Combined Overall Performance Score								98.9%

The resulting payout amounts for the NEOs for the 2012 performance grants are shown below and are also reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

Name	2012 Performance Grant Award			Overall Performance Score			Calculated Performance Grant Payout
Thomas F. Farrell II	$	1,125,250	X		98.9%	=	$	1,112,872
Mark F. McGettrick		521,794	X		98.9%	=		516,054
David A. Christian		399,289	X		98.9%	=		394,897
Paul D. Koonce		256,976	X		98.9%	=		254,150
David A. Heacock		130,250	X		98.9%	=		128,817

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.

Employee and Executive Benefits

Benefit plans and limited perquisites compose the fourth element of Dominion’s 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 (the Dominion Pension Plan) 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 the company 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. The company began funding the special retirement account for eligible employees in January 2001. The formula for the Dominion Pension Plan is explained in the narrative following the Pension Benefits table. The change in Dominion Pension Plan value for 2013 for the NEOs is included in the Summary Compensation Table.

All participating employees in the 401(k) Plan (including the NEOs) are eligible to receive a matching contribution. 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 the 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 Dominion Pension Plan and 401(k) Plan, these plans are unfunded, unsecured obligations of the company. These plans keep Dominion competitive in attracting and retaining officers. Due to the 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 Dominion Pension Plan and 401(k) Plan alone will produce a lower percentage of replacement income in retirement for officers than these plans will provide for other employees. The BRP restores benefits that will not be paid under the Dominion Pension Plan due to 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 Dominion Pension Plan, 401(k) Plan, BRP and ESRP do not include long-term incentive compensation in benefit calculations and, therefore, a significant portion of the potential compensation for 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. Effective July 1, 2013, the ESRP is closed to any new participants.

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 2013.

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

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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 its 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, Dominion’s Board of Directors has directed Mr. Farrell to use the aircraft for all travel, including personal travel, whenever it is feasible to do so. Mr. Farrell’s family and guests may accompany him 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 its executives for business purposes. During 2013, 94% of the use of Dominion’s aircraft was for business purposes. None of the NEOs’ compensation for use of the company aircraft is attributable to their service for Virginia Power.

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. In addition to these agreements being consistent with the practices of Dominion’s peer companies for competitive purposes, the most important reason for these agree-

ments 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 most benefits. 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 with 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 2013.

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 the company. 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

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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 count toward the ownership targets. Restricted stock, goal-based stock and shares underlying stock options do not count toward 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 all after-tax shares from the vesting of 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. An officer 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, 2014, 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		625,665		145,000
Mark F. McGettrick		176,423		35,000
David A. Christian		56,270		35,000
Paul D. Koonce		84,028		35,000
David A. Heacock		24,561		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 of Directors 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. Dominion’s AIP and long-term incentive performance grant documents

include a broader clawback provision that 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

Section 162(m) of the IRC generally disallows a deduction by publicly held corporations for compensation in excess of $1 million paid to the CEO and the 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 generally seeks 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 incentive compensation programs and approving payouts under such programs, it reserves the right to approve, and in some cases has approved, non-deductible compensation when it feels that 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 has not been 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.

149

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 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 2013 was as follows: Mr. Farrell, 32%; Mr. McGettrick, 49%; Mr. Christian, 60%; Mr. Koonce 40%; and Mr. Heacock, 52%.

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.

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 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 Dominion Pension Plan 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.

150

SUMMARY COMPENSATION TABLE

The following table presents information concerning compensation paid or earned by the NEOs for the years ended December 31, 2013, 2012 and 2011 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		2013	$	433,605	$	1,350,305	$	1,657,523	$	—	$	34,148	$	3,475,581
		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
Mark F. McGettrick Executive Vice President and Chief Financial Officer		2013		349,825		573,984		868,677		—		42,724		1,835,210
		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
David A. Christian President and COO (Dominion Generation)		2013		375,134		439,250		734,165		166,946		60,933		1,776,428
		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
Paul D. Koonce President and COO (DVP)		2013		237,744		293,781		469,098		295,808		23,376		1,319,807
		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
David A. Heacock President and CNO		2013		235,768		156,325		294,660		72,705		23,584		783,042
		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

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, 2013: Messrs. Farrell, Christian, Koonce and Heacock: 3%; and Mr. McGettrick: 5%. 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 in addition to the DVP business unit.

⁽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 2013. See also Note 19 to the Consolidated Financial Statements in Dominion’s 2013 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 2013, and the Outstanding Equity Awards at Fiscal Year-End table for a listing of all outstanding equity awards as of December 31, 2013.

⁽³⁾ The 2013 amounts in this column include the payouts under Dominion’s 2013 AIP and 2012 Performance Grant Awards. All of the NEOs received 100% funding of their 2013 AIP target awards. Messrs. Farrell, McGettrick, Christian and Heacock each received 100% payouts for accomplishment of their goals while Mr. Koonce received a 99.97% payout. The 2013 AIP payout amounts were as follows: Mr. Farrell: $544,651; Mr. McGettrick: $352,623; Mr. Christian: $339,268; Mr. Koonce: $214,948; and Mr. Heacock: $165,843. See CD&A for additional information on the 2013 AIP and the Grants of Plan-Based Awards table for the range of each NEO’s potential award under the 2013 AIP. The 2012 Performance Grant Award was issued on February 1, 2012 and the payout amount was determined based on achievement of performance goals for the performance period ended December 31, 2013. Payouts can range from 0% to 200%. The actual payout was 98.9% of the target amount. The 2012 performance grant payout amounts were as follows: Mr. Farrell: $1,112,872; Mr. McGettrick: $516,054; Mr. Christian: $394,897; Mr. Koonce: $254,150; and Mr. Heacock: $128,817. The 2012 performance grant payouts were allocated based on the percentage of the executive’s services performed for Virginia Power during 2013. See Payout Under 2012 Performance Grants of CD&A for additional information on the 2012 performance grants. The 2012 amounts reflect both the 2012 AIP and the 2011 performance grant payouts, and the 2011 amounts reflect both the 2011 AIP and 2010 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 Dominion Pension Plan 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. Reductions in the actuarial present value of an NEO’s accumulated pension benefits are reported as $0. A change in the discount rate can be a significant factor in the change reported in this column. A decrease in the discount rate results in an increase in the present value of the accumulated benefit without any increase in the benefits payable to the NEO at retirement and an increase in the discount rate has the opposite effect. The discount rate used in determining the present value of the accumulated benefit increased from 4.40% used as of December 31, 2012 to a discount rate of 5.30% used as of December 31, 2013. The decrease in present value attributed solely to the change in discount rate was as follows: Mr. Farrell: $(581,168); Mr. McGettrick: $(525,923); Mr. Christian: $(457,868); Mr. Koonce: $(241,417); and Mr. Heacock: $(211,425).

⁽⁵⁾ All Other Compensation amounts for 2013 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	$	8,155	$	9,468	$	2,459	$	14,066	$	34,148
Mark F. McGettrick		14,872		13,859		5,009		8,984		42,724
David A. Christian		19,130		26,797		6,148		8,858		60,933
Paul D. Koonce		10,656		5,587		3,084		4,049		23,376
David A. Heacock		6,828		7,325		5,314		4,117		23,584

151

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.

(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.

(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, 2013.

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
2013 Annual Incentive Plan(2)			$	—	$	544,651	$	1,089,302
2013 Cash Performance Grant(3)				—		1,350,300		2,700,600
2013 Restricted Stock Grant(4)	2/1/2013	1/24/2013								24,927	$	1,350,305
Mark F. McGettrick
2013 Annual Incentive Plan(2)				—		352,623		705,246
2013 Cash Performance Grant(3)				—		573,973		1,147,946
2013 Restricted Stock Grant(4)	2/1/2013	1/24/2013								10,595		573,984
David A. Christian
2013 Annual Incentive Plan(2)				—		339,268		678,535
2013 Cash Performance Grant(3)				—		439,218		878,435
2013 Restricted Stock Grant(4)	2/1/2013	1/24/2013								8,108		439,250
Paul D. Koonce
2013 Annual Incentive Plan(2)				—		215,013		430,026
2013 Cash Performance Grant(3)				—		293,759		587,518
2013 Restricted Stock Grant(4)	2/1/2013	1/24/2013								5,423		293,781
David A. Heacock
2013 Annual Incentive Plan(2)				—		165,843		331,685
2013 Cash Performance Grant(3)				—		156,300		312,600
2013 Restricted Stock Grant(4)	2/1/2013	1/24/2013								2,885		156,325

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 24, 2013, the CGN Committee approved the 2013 long-term incentive compensation awards for Dominion officers, which consisted of a restricted stock grant and a cash performance grant. The 2013 restricted stock award was granted on February 1, 2013. 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, 2013 restricted stock grant was $54.17 per share, which was Dominion’s closing stock price on February 1, 2013.

⁽²⁾  Amounts represent the range of potential payouts under the 2013 AIP. Actual amounts paid under the 2013 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 2013 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 2013 performance grant of the LTIP. Payouts can range from 0% to 200% of the target award. Awards will be paid by March 15, 2015, depending on the achievement of performance goals for the two-year period ending December 31, 2014. 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, 2014 relative to the TSR of the companies that are listed as members of the Philadelphia Utility Index as of the end of the performance period. ROIC goal achievement will be scored against 2013 and 2014 budget goals. See Exhibit 10.2 to Dominion’s Form 8-K filed on January 25, 2013 for TSR and ROIC 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.

152

⁽⁴⁾ The 2013 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 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.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

The following table summarizes equity awards made to NEOs that were outstanding as of December 31, 2013. There were no unexercised or unexercisable option awards outstanding for any NEOs as of December 31, 2013.

	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		25,844	(2)	$	1,671,848
		22,317	(3)		1,443,687
		24,927	(4)		1,612,528
		36,206	(5)		2,342,166
Mark F. McGettrick		11,279	(2)		729,639
		10,348	(3)		669,412
		10,595	(4)		685,391
		24,424	(6)		1,579,989
David A. Christian		7,786	(2)		503,676
		7,919	(3)		512,280
		8,108	(4)		524,507
		17,983	(6)		1,163,320
Paul D. Koonce		5,208	(2)		336,906
		5,096	(3)		329,660
		5,423	(4)		350,814
		12,028	(6)		778,091
David A. Heacock		2,991	(2)		193,488
		2,583	(3)		167,094
		2,885	(4)		186,631

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 market value is based on closing stock price of $64.69 on December 31, 2013.

⁽²⁾  Shares scheduled to vest on February 1, 2014.

⁽³⁾  Shares scheduled to vest on February 1, 2015.

⁽⁴⁾ Shares scheduled to vest on February 1, 2016.

⁽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.

153

OPTION EXERCISES AND STOCK VESTED

The following table provides information about the value realized by NEOs during the year ended December 31, 2013 on vested restricted stock awards. There were no option exercises by NEOs in 2013.

	Stock Awards
Name	Number of Shares Acquired on Vesting		Value Realized on Vesting
Thomas F. Farrell II		30,038	$	1,943,158
Mark F. McGettrick		11,799		763,277
David A. Christian		6,838		442,350
Paul D. Koonce		6,053		391,569
David A. Heacock		3,129		202,415

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, 2013, 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		18.00	$	335,194
	Benefit Restoration Plan		29.00		3,443,656
	Supplemental Retirement Plan		29.00		4,142,899
Mark F. McGettrick	Dominion Pension Plan		29.50		726,651
	Benefit Restoration Plan		30.00		2,939,371
	Supplemental Retirement Plan		30.00		3,211,235
David A. Christian	Dominion Pension Plan		29.50		1,082,455
	Benefit Restoration Plan		29.50		2,238,052
	Supplemental Retirement Plan		29.50		2,949,044
Paul D. Koonce	Dominion Pension Plan		15.00		273,326
	Benefit Restoration Plan		15.00		390,794
	Supplemental Retirement Plan		15.00		1,882,681
David A. Heacock	Dominion Pension Plan		26.50		758,509
	Benefit Restoration Plan		26.50		614,636
	Supplemental Retirement Plan		26.50		745,467

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 Dominion Pension Plan are actual years accrued by an NEO from his date of participation to December 31, 2013. Service for the BRP and the ESRP is the NEO’s actual credited service as of December 31, 2013 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 $1,560,187 lower for Mr. Farrell and $1,217,049 lower for Mr. McGettrick. Dominion Pension Plan and ESRP benefit amounts are not augmented by the additional service credit assumptions.

154

Dominion Pension Plan

The Dominion Pension Plan is a tax-qualified defined benefit pension plan. All of the NEOs participate in the Dominion Pension Plan. The Dominion Pension Plan 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 Dominion Pension Plan 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 Dominion Pension Plan 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 annu-

ally (2.88% in 2013). 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 2013, the compensation limit was $255,000. The IRC also limits the total annual benefit that may be provided to a participant under a qualified defined benefit plan. For 2013, this limitation was the lesser of (i) $205,000 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 Dominion Pension Plan 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 Dominion Pension Plan 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 IRS salary limit is not applied) used to determine the participant’s default annuity form of benefit under the Dominion Pension Plan (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 Dominion Pension Plan. To accommodate the enactment of Section 409A of the IRC, 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 Dominion Pension Plan generally is not entitled to a restoration benefit. Messrs. Farrell and McGettrick have been granted age and service credits for purposes of calculating their Dominion Pension Plan and BRP benefits. Per his letter agreement, Mr. Farrell was granted 25 years of service

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when he reached age 55 and will continue to accrue service as long as he remains employed. At age 60, Mr. Farrell’s benefits will be calculated based on 30 years of service, if he remains employed. Mr. McGettrick, having attained age 50, has earned benefits calculated based on five additional years of age and service. For each of these NEOs, the additional years of service count toward 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 (except that the IRS salary limit is not applied) as the 50% qualified pre-retirement survivor annuity payable under the Dominion Pension Plan and paid in a lump sum payment.

Dominion Executive Supplemental Retirement Plan

The Dominion 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 Section 409A of the IRC, 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. Effective July 1, 2013, the ESRP is closed to any new participants.

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 he attains 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 the company 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 Dominion Pension Plan benefits are prescribed by the terms of the Dominion Pension Plan based on the 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, 2013 benefit calculations shown in the Pension Benefits table include a discount rate of 5.30% to determine the present value of the future benefit obligations for the Dominion Pension Plan, BRP and ESRP and a lump sum interest rate of 4.55% 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. For purposes of estimating future eligibility for unreduced Dominion Pension Plan and ESRP benefits, the effect of future service is considered. Each NEO is assumed to commence Dominion Pension Plan 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 Dominion Pension Plan 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 2018) 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; Dominion 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 2013, a 4.61% 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.

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NONQUALIFIED DEFERRED COMPENSATION

Name	Aggregate Earnings in Last FY (as of 12/31/2013)*		Aggregate Withdrawals/ Distributions (as of  12/31/2013)		Aggregate Balance at Last FYE (as of 12/31/2013)
Thomas F. Farrell II	$	—	$	—	$	—
Mark F. McGettrick		—		—		—
David A. Christian		74		—		17,824
Paul D. Koonce		105,424		—		665,581
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 28 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 2013 as follows: Dominion Resources Stock Fund, 29.8%; and Dominion Fixed Income Fund, 3.01%.

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 the company, 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 match 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 NEOs that are participants in the Frozen DSOP held options on the publicly available mutual fund, Vanguard Short-Term Bond Index, which had a rate of return for 2013 of 0.07%.

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POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL

Under certain circumstances, the company provides benefits to eligible employees upon termination of employment, including a termination of employment involving a change in control of the company, 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.

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 of Directors 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 the company 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 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 Section 280G of the IRC and the executive incurs the excise tax, the company 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 the company 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.

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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, 2013. 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.

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		$—	$	3,040,477	$	645,795	$	435,721		$—	$—		$—		$—	$	4,121,993
Death / Disability		—		4,484,824		645,795		—		—	—		—		—		5,130,619
Change in Control(5)		336,818		3,131,991		704,505		—		3,207,734	—		8,038		—		7,389,086
Mark F. McGettrick(4)
Retirement		—		1,346,540		274,509		—		—	—		—		—		1,621,049
Death / Disability		—		1,917,084		274,509		—		—	—		—		—		2,191,593
Change in Control(5)		—		2,318,076		299,464		—		2,342,891	—		12,278		—		4,972,709
David A. Christian(4)
Retirement		—		977,290		210,061		—		—	—		—		—		1,187,351
Death / Disability		—		1,397,392		210,061		—		—	—		—		—		1,607,453
Change in Control(5)		138,649		1,726,691		229,157		—		2,271,402	—		15,068		1,806,233		6,187,200
Paul D. Koonce
Termination Without Cause		—		645,368		140,494		—		—	—		—		—		785,862
Voluntary Termination		—		—		—		—		—	—		—		—		—
Termination With Cause		—		—		—		—		—	—		—		—		—
Death / Disability		—		926,343		140,494		—		—	—		—		—		1,066,837
Change in Control(5)		1,112,408		1,150,184		153,265		—		1,442,855	35,977		10,078		1,725,712		5,630,479
David A. Heacock(4)
Retirement		—		351,932		74,752		—		—	—		—		—		426,684
Change in Control(5)		715,138		195,413		81,548		—		1,259,576	68,617		13,025		1,032,354		3,365,671

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 2011, 2012 and 2013 under the LTIP vest pro rata upon termination without cause, death or disability. These grants vest pro rata upon retirement provided the CEO (or in the case of the CEO, the CGN Committee) does not determine the NEO’s retirement is detrimental to Dominion; 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 $64.69 on December 31, 2013.

⁽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. Koonce is eligible for retiree medical and executive life insurance upon a change in control. Mr. Heacock is eligible for retiree medical upon a change in control.

⁽⁴⁾  For the NEOs who are eligible for retirement (Messrs. Farrell, McGettrick, Christian and Heacock), this table 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, 2013. 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 without cause.

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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 2014 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 2014 Proxy Statement is incorporated by reference.

VIRGINIA POWER

The table below sets forth as of February 15, 2014, 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		666,908		321,415		988,323
Mark F. McGettrick		189,925		109,594		299,519
Paul D. Koonce		75,733		66,669		142,402
David A. Christian		64,765		67,165		131,930
David A. Heacock		28,487		15,652		44,139
Mark O. Webb		5,681		3,430		9,111
All directors and executive officers as a group (8 persons)(2)		1,084,562		603,649		1,688,211

(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. Webb, 409 (shares held jointly) and 90 (shares held by spouse); all directors and executive officers as a group, 44,458.

(2) Neither any individual director or executive officer, nor all of the directors and executive officers as a group, own more than 1% of Dominion common shares outstanding as of February 15, 2014.

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 2014 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 http://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, 2013, 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.

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Director Independence

Under NYSE listing standards, Messrs. Farrell, McGettrick and Webb are not independent as they were executive officers of Virginia Power and 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 2014 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, 2013 and 2012.

Type of Fees	2013		2012
(millions)
Audit fees	$	1.89	$	1.79
Audit-related fees		0.02		—
Tax fees		—		—
All other fees		—		—
	$	1.91	$	1.79

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.

Audit-Related Fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Virginia Power’s consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and attest services not required by statutes or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.

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 2013 meeting, the Dominion Audit Committee approved Virginia Power’s schedule of services and fees for 2014. 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.

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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 57.

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 noted)

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 3.1.b, Form 10-Q filed April 29, 2011, File No. 1-2255).				X
3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective May 3, 2013 (Exhibit 3.1, Form 8-K filed May 3, 2013, File No. 1-8489).		X
3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).				X
4	Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.		X		X
4.1.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 Indenture (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		X		X

162

Exhibit Number	Description	Dominion		Virginia Power
	November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, 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);		X

163

Exhibit Number	Description	Dominion		Virginia Power
	Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Forms of Seventeenth and Eighteenth Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489; Forms of Twentieth and Twenty-First Supplemental Indentures, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Third Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489); Forty-First Supplemental Indenture, dated March 1, 2011 (Exhibit 4.3, Form 8-K, filed March 7, 2011, File No. 1-8489); Forty-Second Supplemental Indenture, dated March 1, 2011 (Exhibit 4.4, Form 8-K, filed March 7, 2011, File No. 1- 8489); Forty- Third Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 5, 2011, File No. 1-8489); Forty-Fourth Supplemental Indenture, dated August 1, 2011 (Exhibit 4.3, Form 8-K, filed August 15, 2011, File No. 1-8489); Forty-Fifth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.3, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Sixth Supplemental Indenture, dated September 1, 2012 (Exhibit 4.4, Form 8-K, filed September 13, 2012, File No. 1-8489); Forty-Seventh Supplemental Indenture, dated September 1, 2012 (Exhibit 4.5, Form 8-K, filed September 13, 2012, File No. 1-8489).
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

164

Exhibit Number	Description	Dominion		Virginia Power
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) ; Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, 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
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
4.13	Series A Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.7, Form 8-K filed June 7, 2013, File No. 1-8489).		X
4.14	Series B Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.8, Form 8-K filed June 7, 2013, 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), 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) , 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		X		X

165

Exhibit Number	Description	Dominion		Virginia Power
	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).
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*	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
10.9*	Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company dated January 24, 2013 (effective for certain officers elected subsequent to February 1, 2013) (filed herewith).		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), as amended and restated effective July 1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013 filed August 6, 2013 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 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. 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
10.19*	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
10.20*	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

166

Exhibit Number	Description	Dominion		Virginia Power
10.21*	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
10.22*	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
10.23*	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
10.24*	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
10.25*	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
10.26*	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
10.27*	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
10.28*	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
10.29*	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
10.30*	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
10.31*	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
10.32*	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
10.33*	Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012, File No. 1-8489).		X		X
10.34*	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
10.35*	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
10.36*	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
10.37*	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
10.38*	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
10.39*	Retirement Agreement, dated as of June 20, 2013, between Dominion Resources, Inc. and Gary L. Sypolt (Exhibit 10.1, Form 8-K filed June 24, 2013, File No. 1-8489).		X
10.40*	2014 Performance Grant Plan under 2014 Long-Term Incentive Program approved January 16, 2014 (filed herewith).		X		X
10.41*	Form of Restricted Stock Award Agreement under the 2014 Long-term Incentive Program approved January 16, 2014 (filed herewith).		X		X

167

Exhibit Number	Description	Dominion		Virginia Power
10.42*	Form of Special Performance Grant for Thomas F. Farrell II and Mark F. McGettrick approved January 16, 2014 (filed herewith).		X		X
10.43*	Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).		X
10.44*	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
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	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, 2013, filed on February 27, 2014, 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

168

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 27, 2014

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 27th day of February, 2014.

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/    James O. Ellis, Jr.          James O. Ellis, Jr.	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/    Pamela J. Royal         Pamela J. Royal	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, Controller and Chief Accounting Officer

169

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 27, 2014

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 27th day of February, 2014.

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, Controller and Chief Accounting Officer
/S/    MARK O. WEBB         Mark O. Webb	Director

170

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 3.1.b, Form 10-Q filed April 29, 2011, File No. 1-2255).				X
3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective May 3, 2013 (Exhibit 3.1, Form 8-K filed May 3, 2013, File No. 1-8489).		X
3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).				X
4	Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.		X		X
4.1.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 Indenture (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); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed		X		X

171

Exhibit Number	Description	Dominion		Virginia Power
	August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, 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 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		X

172

Exhibit Number	Description	Dominion		Virginia Power
	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) ; Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489).		X

173

Exhibit Number	Description	Dominion		Virginia Power
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
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
4.13	Series A Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.7, Form 8-K filed June 7, 2013, File No. 1-8489).		X
4.14	Series B Purchase Contract and Pledge Agreement, dated as of June 7, 2013, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.8, Form 8-K filed June 7, 2013, 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), 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) , 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*	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

174

Exhibit Number	Description	Dominion		Virginia Power
10.9*	Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company dated January 24, 2013 (effective for certain officers elected subsequent to February 1, 2013) (filed herewith).		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), as amended and restated effective July 1, 2013 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2013 filed August 6, 2013 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 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. 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
10.19*	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
10.20*	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
10.21*	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
10.22*	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
10.23*	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

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Exhibit Number	Description	Dominion		Virginia Power
10.24*	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
10.25*	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
10.26*	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
10.27*	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
10.28*	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
10.29*	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
10.30*	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
10.31*	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
10.32*	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
10.33*	Form of Restricted Stock Award Agreement for Mark F. McGettrick, Paul D. Koonce and David A. Christian approved December 17, 2012 (Exhibit 10.1, Form 8-K filed December 21, 2012, File No. 1-8489).		X		X
10.34*	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
10.35*	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
10.36*	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
10.37*	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
10.38*	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
10.39*	Retirement Agreement, dated as of June 20, 2013, between Dominion Resources, Inc. and Gary L. Sypolt (Exhibit 10.1, Form 8-K filed June 24, 2013, File No. 1-8489).		X
10.40*	2014 Performance Grant Plan under 2014 Long-Term Incentive Program approved January 16, 2014 (filed herewith).		X		X
10.41*	Form of Restricted Stock Award Agreement under the 2014 Long-term Incentive Program approved January 16, 2014 (filed herewith).		X		X
10.42*	Form of Special Performance Grant for Thomas F. Farrell II and Mark F. McGettrick approved January 16, 2014 (filed herewith).		X		X
10.43*	Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).		X
10.44*	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

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Exhibit Number	Description	Dominion		Virginia Power
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
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	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, 2013, filed on February 27, 2014, 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

177

EX-10.9

Exhibit 10.9

EMPLOYMENT CONTINUITY AGREEMENT

THIS AGREEMENT dated as of                    (the “Agreement Date”) is made by and between Dominion Resources, Inc. (“DRI” or the “Company”), a Virginia corporation, and                    (the “Executive”).

ARTICLE I

PURPOSES

The Board of Directors of DRI (the “Board”) has determined that it is in the best interests of the Company and its shareholders to assure that the Company will have the continued services of the Executive, despite the possibility or occurrence of a Change in Control of the Company. The Board believes that this objective may be achieved by giving key management employees assurances of financial security in case of a pending or threatened change in control, so that they will not be distracted by personal risks and will continue to devote their full time and best efforts to the performance of their duties. The Board also wants to provide the Executive with compensation and benefits arrangements upon a Change in Control which are competitive with those of similarly situated corporations.

ARTICLE II

CERTAIN DEFINITIONS

When used in this Agreement, the terms specified below shall have the following meanings:

2.1 “Agreement Term” means:

(a) Except as provided in Section 2.1(b), the period commencing on the Agreement Date and ending on December 31 of the second calendar year following the Agreement Date. Commencing on the next January 1 after the initial term and each subsequent January 1, the Agreement Term shall be automatically extended for an additional one-year term, unless by December 1 of the last year of the initial term or of any subsequent year in the Agreement Term, the Company shall give notice to the Executive that the Agreement Term shall not be extended. The Agreement Term also shall include the Employment Period.

(b) If a Potential Change in Control (as defined below) occurs, the Agreement Term shall be automatically extended to the later of (i) the period described in Section 2.1(a) or (ii) 30 days after the date either the Change in Control is completed or a public announcement is made that the transaction will not occur (the “Change in Control Extension”). Commencing on the day immediately after the expiration of the Change in Control Extension, and each subsequent anniversary of such day, the

Agreement Term shall be automatically extended for an additional one-year term, unless at least 30 days prior to the last day of the Change in Control Extension or of any such extended Agreement Term, the Company shall give notice to the Executive that the Agreement Term shall not be extended. A Potential Change in Control shall be deemed to have occurred if (i) the Company enters into an agreement, the consummation of which would result in the occurrence of a Change in Control of the Company, (ii) the Company or any person publicly announces an intention to take or to consider taking actions which, if consummated, would constitute a Change in Control of the Company; or (iii) the Board adopts a resolution to the effect that a Potential Change in Control of the Company has occurred for purposes of this Agreement.

2.2 “Accrued Obligation” See Section 5.4(a).

2.3 “Annual Base Salary” See Section 3.2(a).

2.4 “Annual Bonus” See Section 3.2(b).

2.5 “Bonus Plan” See Section 3.2(b).

2.6 “Cause” See Section 4.3.

2.7 “Change in Control” means:

(a) any person, including a “group” as defined in Section 13(d)(3) of the Securities Exchange Act of 1934, as amended, becomes the owner or beneficial owner of DRI securities having 20% or more of the combined voting power of the then outstanding DRI securities that may be cast for the election of DRI’s directors (other than as a result of an issuance of securities initiated by DRI, or open market purchases approved by the DRI Board, as long as the majority of the DRI Board approving the purchases is also the majority at the time the purchases are made); or

(b) as the direct or indirect result of, or in connection with, a cash tender or exchange offer, a merger or other business combination, a sale of assets, a contested election, or any combination of these transactions, the persons who were directors of DRI before such transactions cease to constitute a majority of the DRI Board, or any successor’s board, within two years of the last of such transactions.

2.8 “Code” means the Internal Revenue Code of 1986, as amended

2.9 “Disability” See Section 4.1.

2.10 “Disability Effective Date” See Section 4.1

2.11 “Effective Date” means the first date during the Agreement Term on which a Change in Control occurs. Anything in this Agreement to the contrary notwithstanding, if a Change in Control occurs and the Executive’s employment with the Company had

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terminated prior to the date on which the Change in Control occurs, and if it is reasonably demonstrated by the Executive that such termination of employment (a) was at the request of a third party who has taken steps reasonably calculated to effect a Change in Control, or (b) otherwise arose in connection with or in anticipation of a Change in Control, then for all purposes of this Agreement, the “Effective Date” shall mean the date immediately prior to the date of such termination of employment.

2.12 “Employment Period” means the period commencing on the Effective Date and ending on the third anniversary of such date.

2.13 “Performance Period” See Section 3.2(b).

2.14 “Plans” See Section 3.2(c).

2.15 “Severance Incentive” means the greater of (i) the target annual incentive under an Incentive Plan applicable to the Executive for the Performance Period in which the Termination Date occurs, or (ii) the highest actual annual incentives paid (or payable, to the extent not previously paid) to the Executive under the Incentive Plan during the three calendar years preceding the calendar year in which the Termination Date occurs.

2.16 “Termination Date” means the date of termination of the Executive’s employment; provided, however, that if the Executive’s employment is terminated by reason of Disability, then the Termination Date shall be the Disability Effective Date.

2.17 “Welfare Plans” See Section 3.2(d).

ARTICLE III

TERMS OF EMPLOYMENT

3.1 Position and Duties.

(a) The Company agrees to continue the Executive in its employ during the Employment Period and, subject to Article IV of this Agreement, the Executive agrees to remain in the employ of the Company subject to the terms and conditions hereof.

(b) During the Employment Period, the Executive (i) will devote his or her or her knowledge, skill and best efforts on a full-time basis to performing his or her or her duties and obligations to the Company (with the exception of absences on account of illness or vacation in accordance with the Company’s policies and civic and charitable commitments not involving a conflict with the Company’s business), and (ii) will comply with the directions and orders of the Board of Directors, the Chief Executive Officer or other superior officer of the Company with respect to the performance of his or her duties.

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3.2 Compensation.

(a) Base Salary. During the Employment Period, the Executive shall receive an annual base salary (“Annual Base Salary”), which shall be paid at a monthly rate at least equal to twelve times the highest monthly base salary paid or payable, including any base salary which has been earned but deferred, to the Executive by the Company in respect of the twelve-month period immediately preceding the month in which the Effective Date occurs. During the Employment Period, the Annual Base Salary shall be reviewed no more than 12 months after the last salary increase awarded to the Executive prior to the Effective Date and, thereafter, at least annually, and shall be increased at any time and from time to time as shall be substantially consistent with increases in base salary awarded to other peer executives of the Company. Annual Base Salary shall not be reduced after any such increase unless such reduction is part of a policy, program or arrangement applicable to peer executives of the Company and of any successor entity, and the term Annual Base Salary as used in this Agreement shall refer to Annual Base Salary as so adjusted.

(b) Annual Bonus. In addition to Annual Base Salary, the Company shall make or cause to be made to the Executive an incentive award (the “Annual Bonus”) for each Performance Period which ends during the Employment Period. “Performance Period” means each period of time designated in accordance with any annual incentive award arrangement (“Bonus Plan”) which is based upon performance. The Executive’s target and maximum Annual Bonus with respect to any Performance Period shall not be less than the largest target and maximum annual incentive award payable with respect to the Executive under the Company’s annual incentive program as in effect at any time in the three-year period immediately preceding the Effective Date.

(c) Incentive, Savings and Retirement Plans. During the Employment Period, the Executive shall be entitled to participate in all incentive, savings and retirement plans, practices, policies and programs (“Plans”) applicable generally to other peer executives of the Company, but in no event shall such Plans provide the Executive with incentives or savings and retirement benefits which, in each case, are less favorable, in the aggregate than the greater of (i) those provided by the Company for the Executive under such Plans as in effect at any time during the 90-day period immediately preceding the Effective Date, or (ii) those provided generally at any time after the Effective Date to other peer executives of the Company. The Plans shall include both tax-qualified retirement plans and nonqualified retirement plans.

(d) Welfare Benefit Plans. During the Employment Period, the Executive and/or the Executive’s family, as the case may be, shall be eligible for participation in and shall receive all benefits under welfare benefit plans, practices, policies and programs (“Welfare Plans”) provided by the Company (including, without limitation, medical, prescription, dental, disability, salary continuance, employee life, group life, accidental death and travel accident insurance benefits), but in no event shall

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such Welfare Plans provide the Executive with benefits which are less favorable, in the aggregate than the greater of (i) those provided by the Company for the Executive under such Welfare Plans as were in effect at any time during the 90-day period immediately preceding the Effective Date, or (ii) those provided generally at any time after the Effective Date to other peer executives of the Company.

(e) Other Employee Benefits. During the Employment Period, the Executive shall be entitled to other employee benefits and perquisites in accordance with the most favorable plans, practices, programs and policies of the Company, as in effect with respect to the Executive at any time during the 90-day period immediately preceding the Effective Date, or if more favorable, as in effect generally with respect to other peer executives of the Company. These other employee benefits and perquisites include, but are not limited to, vacation, use of a company car, parking benefits and financial planning.

(f) Stock Incentives. The provisions of the applicable award agreement shall control the extent, if any, to which (i) any stock incentive award granted to the Executive under any Plan which has not become exercisable as of the Effective Date shall vest; (ii) any forfeiture conditions that as of the Effective Date are applicable to any deferred stock unit, restricted stock or restricted share units awarded to the Executive by the Company pursuant to the Dominion Resources, Inc. 2005 Incentive Compensation Plan or any other plan or arrangement (“Incentive Plans”), a successor plan or otherwise shall lapse; or (iii) any stock options (including options vested as of the Exercise Date) shall remain exercisable. If the effect of a Change in Control is not specifically addressed in the applicable award agreement, (i) on the Effective Date, the Executive shall become fully vested in any and all stock incentive awards granted to the Executive under any Plan which have not become exercisable as of the Effective Date; and (ii) all forfeiture conditions that as of the Effective Date are applicable to any deferred stock unit, restricted stock or restricted share units awarded to the Executive by the Company pursuant to any Incentive Plan or otherwise shall lapse immediately at the Effective Date.

(g) Subsidiaries. To the extent that immediately prior to the Effective Date, the Executive has been on the payroll of, and participated in the incentive or employee benefit plans of, a subsidiary of DRI, the references to the Company contained in Sections 3.2(a) through 3.2(f) and the other Sections of this Agreement referring to compensation and benefits to which the Executive may be entitled shall be read to refer to such subsidiary.

ARTICLE IV

TERMINATION OF EMPLOYMENT

4.1 Disability. During the Agreement Term, the Company may terminate the Executive’s employment upon the Executive’s Disability. The Executive’s employment shall terminate effective on the 30th day (the “Disability Effective Date”) after the

5

Executive’s receipt of written notice of termination from the Company unless, before the Disability Effective Date, the Executive shall have resumed the full-time performance of the Executive’s duties. “Disability” means a condition, resulting from bodily injury or disease, that renders, and for a six consecutive month period has rendered, the Executive unable to perform substantially the duties pertaining to his or her employment with the Company. A return to work of less than 14 consecutive days will not be considered an interruption in the Executive’s six consecutive months of disability. Disability will be determined by the Company on the basis of medical evidence satisfactory to the Company.

4.2 Death. The Executive’s employment shall terminate automatically upon the Executive’s death during the Agreement Term.

4.3 Cause. The Company may terminate the Executive’s employment during the Employment Period for Cause. For purposes of this Agreement, “Cause” means (a) fraud or material misappropriation with respect to the business or assets of the Company, (b) persistent refusal or willful failure of the Executive to perform substantially his or her duties and responsibilities to the Company, which continues after the Executive receives notice of such refusal or failure, (c) conviction of a felony or crime involving moral turpitude, or (d) the use of drugs or alcohol that interferes materially with the Executive’s performance of his or her duties.

4.4 Constructive Termination. The Executive may terminate the Executive’s employment for Constructive Termination at any time during the Employment Period. “Constructive Termination” means any material breach of this Agreement by the Company during the Employment Period, including:

(a) the failure to maintain the Executive in the office or position, or in a substantially equivalent office or position, held by the Executive immediately prior to the Effective Date;

(b) a material adverse alteration in the nature or scope of the Executive’s position, duties, functions, responsibilities or authority as compared to the nature or scope immediately prior to the Effective Date;

(c) a reduction of the Executive’s Annual Base Salary in violation of Section 3.2(a) or a reduction in the Executive’s Annual Bonus in violation of Section 3.2(b);

(d) a failure by the Company to provide the Executive with increase in Annual Base Salary or participation in Bonus Plans or Incentive Plans comparable to peer executives of the Company;

(e) the failure of any successor to the Company to assume this Agreement;

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(f) a relocation of more than 50 miles of (i) the Executive’s workplace, or (ii) the principal offices of the Company (if such offices are the Executive’s workplace), in each case without the consent of the Executive; or

(g) any failure by the Company to comply with Section 3.2(f).

An act or omission shall not constitute Constructive Termination unless (1) the Executive gives written notice to the Company indicating that the Executive intends to terminate employment under this Section 4.4; (2) the Executive’s voluntary termination occurs within 60 days after the Executive knows or reasonably should know of an event described in subsection (a)-(g) above, or within 60 days after the last in a series of such events, and (3) the Company has failed to remedy the event described in subsection (a)-(g) above as the case may be, within 30 days after receiving the Executive’s written notice. If the Company remedies the event described in subsection (a)-(g), as the case may be, within 30 days after receiving the Executive’s written notice, the Executive may not terminate employment under this Section 4.4 on account of the event specified in the Executive’s notice.

ARTICLE V

OBLIGATIONS OF THE COMPANY UPON TERMINATION

5.1 If by the Executive for Constructive Termination or by the Company Other Than for Cause or Disability. If, during the Employment Period, the Company shall terminate the Executive’s employment other than for Cause or Disability, or if the Executive shall terminate employment for Constructive Termination, the Company’s obligations to the Executive shall be as follows:

(a) The Company shall, within thirty business days of such termination of employment, pay the Executive a cash payment equal to the sum of the following amounts:

(i) to the extent not previously paid, the Annual Base Salary and any accrued paid time off through the Termination Date;

(ii) an amount equal to the product of (i) the Annual Bonus (as defined in Section 3.2(b)) for the Performance Period in which the Termination Date occurs multiplied by (ii) a fraction, the numerator of which is the number of days actually worked during such Performance Period, and the denominator of which is 365; or, if greater, the amount of any Annual Incentive paid or payable to the Executive with respect to the Performance Period for the year in which the Termination Date occurs; and

(iii) all amounts previously deferred by the Executive under any nonqualified deferred compensation plan sponsored by the Company, together with any accrued earnings thereon, and not yet paid by the Company.

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(b) The Company shall, within thirty business days of such termination of employment, pay the Executive a cash payment equal to three (3) times the sum of the Executive’s Annual Base Salary and the Severance Incentive.

(c) The provisions of the applicable award agreement shall control the extent, if any, to which (i) any stock incentive award granted to the Executive under any Plan which has not become exercisable as of the Termination Date shall vest; (ii) any forfeiture conditions that as of the Termination Date are applicable to any deferred stock unit, restricted stock or restricted share units awarded to the Executive by the Company pursuant to the Incentive Plan, a successor plan or otherwise shall lapse; or (iii) any stock options (including options vested as of the Termination Date) shall remain exercisable. If the effect of a Change in Control is not specifically addressed in the applicable award agreement, (i) on the Termination Date, the Executive shall become fully vested in any and all stock incentive awards granted to the Executive under any Plan which have not become exercisable as of the Termination Date; and (ii) all forfeiture conditions that as of the Termination Date are applicable to any deferred stock unit, restricted stock or restricted share units awarded to the Executive by the Company pursuant to the Incentive Plan, a successor plan or otherwise shall lapse immediately.

(d) Except as provided in subsections (e) and (f), during the Employment Period (or until such later date as any Welfare Plan of the Company may specify), the Company shall continue to provide to the Executive and the Executive’s family welfare benefits (including, without limitation, disability, individual life and group life insurance benefits, but excluding medical or other health plans) which are at least as favorable as those provided under the most favorable Welfare Plans of the Company applicable (i) with respect to the Executive and his or her family during the 90-day period immediately preceding the Termination Date, or (ii) with respect to other peer executives and their families during the Employment Period. In determining benefits under such Welfare Plans, the Executive’s annual compensation attributable to base salary and incentives for any plan year or calendar year, as applicable, shall be deemed to be not less than the Executive’s Annual Base Salary and Annual Incentive. The cost of the welfare benefits provided under this Section 5.1(d) shall not exceed the cost of such benefits to the Executive immediately before the Termination Date or, if less, the Effective Date. Notwithstanding the foregoing, if the Executive obtains comparable coverage under any Welfare Plans sponsored by another employer, then the amount of coverage required to be provided by the Company hereunder shall be reduced by the amount of coverage provided by such other employer’s Welfare Plans.

(e) If the Executive elects to convert any group term life insurance to an individual policy, the Company shall pay all premiums for 12 months and the Executive shall cease to participate in the Company’s group term life insurance.

(f) The Executive’s eligibility for any retiree medical coverage shall be determined under the relevant plan, with additional age or service credited provided in the Executive’s employment agreement, if any. The Executive’s rights under this

8

Section shall be in addition to and not in lieu of any post-termination continuation coverage or conversion rights the Executive may have pursuant to applicable law, including, without limitation, continuation coverage required by Section 4980B of the Code (“COBRA Continuation Coverage”). If the Executive is not eligible for retiree medical coverage and elects to receive COBRA Continuation Coverage, the Company shall pay all of the required premiums for the Executive and/or the Executive’s family for 12 months after the Termination Date. For purposes of determining eligibility for and the time of commencement of retiree benefits under any Welfare Plans of the Company, the Executive’s credited service shall be the Executive’s credited service at the Termination Date plus five years and the Executive’s age shall be deemed to be the Executive’s age at the Termination Date plus five years. If the Executive is eligible for additional credited service or deemed age under an employment agreement or other contract with the Company, the additional service and age provided by this Section 5.1(f) shall be in addition to any service and/or age credit provided under an employment agreement or contract.

(g) The Executive shall be fully vested in the Company’s Executive Supplemental Retirement Plan and Benefit Restoration Plan or any successor or replacement plans (the “Supplemental Plans”). For purposes of the Supplemental Plans, the Executive’s credited service shall be the Executive’s credited service at the Termination Date plus five years and the Executive’s age shall be deemed to be the Executive’s age at the Termination Date plus five years. The amount payable under Section 5.1(b) of this Agreement shall be taken into account for purposes of determining the amount of benefits to which the Executive is entitled under the Supplemental Plans as though the amount was earned equally over the Employment Period. If the Executive is eligible for additional credited service or deemed age under an employment agreement or other contract with the Company, the additional service and age provided by this Section 5.1(g) shall be in addition to any service and/or age credit provided under an employment agreement or contract.

(h) The Company shall, at its sole expense, as incurred, pay on behalf of Executive up to $25,000 in fees and costs charged by nationally recognized outplacement firm selected by the Executive to provide outplacement service for one year after the Termination Date.

(i) For the period stated below, the Company shall continue to pay all premiums on the Executive’s whole life insurance policy (the “Policy”) issued under the Executive Life Insurance Program. The payments under Section 5.1(i) are in lieu of any payments under Section 5.1(d) with respect to the Policy. The premium payments shall be made until the earlier of:

(i) the fifth anniversary of the Termination Date, or

(ii) the later to occur of the tenth anniversary of the Policy or the Executive reaching age 64.

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(j) Notwithstanding anything in Sections 5.1(a) through (i) to the contrary, if the Company should, in its sole discretion, determine that any right to payment of an amount pursuant to this Agreement (including payments under Article VI) represents the right to payment of deferred compensation subject to Code Section 409A (a “Covered Payment”), then the following provisions shall apply:

(i) If, as of the Termination Date, the Executive is a Specified Executive (as defined below), then no Covered Payment shall be made until as soon as administratively possible after the date that is six months after the Termination Date (the “Postponement Date”), and any Covered Payment(s) that would otherwise have been made to the Executive prior to the Postponement Date shall be withheld and paid to the Executive on the Postponement Date in a lump sum. A “Specified Executive” for purposes of this Agreement is any employee of the Company who, for the twelve month period beginning on any April 1, was, at any time during the twelve month period ending on the immediately preceding December 31, a “key employee” of the Company within the meaning of Code Section 416(i) (without regard to subparagraph (5) thereof).

(ii) Notwithstanding any other provision of the Agreement to the contrary, (A) the time or schedule of any Covered Payment shall not be accelerated for any reason, except as may be specifically provided under Treas. Regs. Section 1.409A-3(j) or any successor provision; and (B) except as otherwise provided in Section 5.1(j)(i), above, or as may be specifically provided in Treas. Regs. Section 1.409A-2(b)(7) or any successor provision, no Covered Payment shall be delayed to a date after the designated payment date.

(k) Notwithstanding any provision of this Agreement to the contrary, if the Executive becomes entitled to payment and/or benefits provided by this Agreement or any other amounts in the nature of compensation, whether alone or together with other payments or benefits that the Executive receives or realizes or is then entitled to receive or realize from the Company or any of its affiliates or any other person whose actions result in a change of ownership or effective control of the Company, and such payments and/or benefits would constitute an “excess parachute payment” within the meaning of Code Section 280G and/or any corresponding and applicable state law provision, the payments and/or benefits provided to the Executive under this Agreement will be reduced by reducing the amount of payments and benefits payable to the Executive (the “280G Reduction”) to the extent necessary so that no portion of the Executive’s payments or benefits will be subject to the excise tax imposed by Section 4999 of the Code or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the “Excise Tax”); but only if (A) the net amount of such payments and benefits, as so reduced (and after subtracting the net amount of federal, state and local income and employment taxes on such reduced payments and benefits) is greater than or equal to (B) the net amount of such payments and benefits without such reduction (but after subtracting the net amount of federal, state and local

10

income and employment taxes on such payments and benefits and the amount of Excise Tax to which the Executive would be subject in respect of such unreduced payments and benefits). Any 280G Reduction pursuant to this paragraph shall be effectuated by reducing the payments and benefits hereunder, to the extent necessary, in the following order: (A) any severance payment due pursuant to Section 5.1(b), (B) any premiums on life insurance under Section 5.1(i), (C) any premiums on life insurance under Section 5.1(e), and (D) the additional credited service or deemed age pursuant to Section 5.1(g).

5.2 If by the Company for Cause. If the Company terminates the Executive’s employment for Cause during the Employment Period, this Agreement shall terminate without further obligation by the Company to the Executive, other than the obligation immediately to pay the Executive in cash the Executive’s Annual Base Salary through the Termination Date, plus any accrued paid time off, in each case to the extent not previously paid.

5.3 If by the Executive Other Than for Constructive Termination. If the Executive terminates employment during the Employment Period other than for Constructive Termination, Disability or death, this Agreement shall terminate without further obligation by the Company, other than the obligation immediately to pay the Executive in cash the Executive’s Annual Base Salary through the Termination Date, plus any accrued paid time off, in each case to the extent not previously paid.

5.4 If by the Company for Disability. If the Company terminates the Executive’s employment by reason of the Executive’s Disability during the Employment Period, this Agreement shall terminate without further obligation to the Executive, other than:

(a) the Company shall pay the Executive in cash all amounts specified in Sections 5.1(a)(i), (ii), (iii) and 5(b), in each case, to the extent unpaid as of the Termination Date (such amounts collectively, the “Accrued Obligations”),

(b) the Executive shall be fully vested in the Company’s Supplemental Plans; and

(c) the Executive’s right after the Disability Effective Date to receive disability and other benefits at least equal to the greater of (1) those provided under the most favorable disability Plans applicable to disabled peer executives of the Company in effect immediately before the Termination Date, or (2) those provided under the most favorable disability Plans of the Company in effect at any time during the 90-day period immediately before the Effective Date.

5.5 If upon Death. If the Executive’s employment is terminated by reason of the Executive’s death during the Employment Period, this Agreement shall terminate without further obligation to the Executive’s legal representatives under this Agreement, other than the obligation immediately to pay the Executive’s estate or beneficiary in

11

cash all Accrued Obligations (as defined in Section 5.4(a)) and to provide the benefits as stated in Section 5.4(b). In addition, the Executive’s family shall be entitled to receive death benefits at least equal to the most favorable death benefits provided under Plans and Welfare Plans of the Company to the surviving families of peer executives of the Company, but in no event shall such Plans and Welfare Plans provide benefits which in each case are less favorable, in the aggregate, than the most favorable of those provided by the Company to the Executive under such Plans in effect at any time during the 90-day period immediately before the Effective Date.

ARTICLE VI

EXPENSES AND INTEREST

6.1 Legal Fees and Other Expenses. The Company will pay all reasonable fees and expenses, if any, (including, without limitation, legal fees and expenses) that are incurred by the Executive to enforce this Agreement and that result from a breach of this Agreement by the Company.

6.2 Interest. If the Company does not pay any amount due to the Executive under this Agreement within three days after such amount became due and owing, interest shall accrue on such amount from the date it became due and owing until the date of payment at a annual rate equal to 200 basis points above the base commercial lending rate published in The Wall Street Journal in effect from time to time during the period of such nonpayment.

ARTICLE VII

NO SET-OFF OR MITIGATION

7.1 No Set-off by Company. The Executive’s right to receive when due the payments and other benefits provided for under this Agreement is absolute, unconditional and subject to no set-off, counterclaim or legal or equitable defense. Any claim which the Company may have against the Executive, whether for a breach of this Agreement or otherwise, shall be brought in a separate action or proceeding and not as part of any action or proceeding brought by the Executive to enforce any rights against the Company under this Agreement.

7.2 No Mitigation. The Executive shall not have any duty to mitigate the amounts payable by the Company under this Agreement by seeking new employment following termination. Except as specifically otherwise provided in this Agreement, all amounts payable pursuant to this Agreement shall be paid without reduction regardless of any amounts of salary, compensation or other amounts which may be paid or payable to the Executive as the result of the Executive’s employment by another employer.

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ARTICLE VIII

NON-EXCLUSIVITY OF RIGHTS

8.1 Waiver of Other Severance Rights. To the extent that payments are made to the Executive pursuant to Section 5.1 of this Agreement, the Executive hereby waives the right to receive benefits under any plan or agreement (including an offer of employment or employment contract) of the Company or its subsidiaries which provides for severance benefits (except as provided in Section 5.1(b)).

8.2 Other Rights. Except as provided in Section 8.1, this Agreement shall not prevent or limit the Executive’s continuing or future participation in any benefit, bonus, incentive or other plans provided by the Company or any of its subsidiaries and for which the Executive may qualify, nor shall this Agreement limit or otherwise affect such rights as the Executive may have under any other agreements with the Company or any of its subsidiaries. Amounts which are vested benefits or which the Executive is otherwise entitled to receive under any plan of the Company or any of its subsidiaries and any other payment or benefit required by law at or after the Termination Date shall be payable in accordance with such Plan or applicable law except as expressly modified by this Agreement.

ARTICLE IX

MISCELLANEOUS

9.1 No Assignment. The Executive’s rights under this Agreement may not be assigned or transferred in whole or in part, except that the personal representative of the Executive’s estate will receive any amounts payable under this Agreement after the death of the Executive. This Agreement shall inure to the benefit of and be enforceable by the Executive’s legal representatives.

9.2 Successors. The rights and obligations of the Company under this Agreement will inure to the benefit of and will be binding upon the successors and assigns of the Company. Before or upon a Change in Control, the Company shall obtain the agreement of the surviving or acquiring corporation that it will succeed to the Company’s rights and obligations under this Agreement.

9.3 Rights Under the Agreement. The right to receive benefits under the Agreement will not give the Executive any proprietary interest in the Company or any of its assets. Benefits under the Agreement will be payable from the general assets of the Company, and there will be no required funding of amounts that may become payable under the Agreement. The Executive will for all purposes be a general creditor of the Company. The interest of the Executive under the Agreement cannot be assigned, anticipated, sold, encumbered or pledged and will not be subject to the claims of the Executive’s creditors.

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9.4 Notice. For purposes of this Agreement, notices and all other communications must be in writing and are effective when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed to the Executive or his or her personal representative at his or her last known address. All notices to the Company must be directed to the attention of the Corporate Secretary with a copy to the General Counsel. Such other addresses may be used as either party may have furnished to the other in writing. Notices of change of address are effective only upon receipt.

9.5 Miscellaneous. The Executive and the Company agree that, effective as of the execution of this Agreement, any prior Employment Continuity Agreement between the Executive and the Company is null and void. This instrument contains the entire agreement of the parties. To the extent not governed by federal law, this Agreement will be construed in accordance with the laws of the Commonwealth of Virginia, without reference to its conflict of laws rules. No provisions of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and the writing is signed by the Executive and the Company. A waiver of any breach of or compliance with any provision or condition of this Agreement is not a waiver of similar or dissimilar provisions or conditions. The invalidity or unenforceability of any provision of this Agreement will not affect the validity or enforceability of any other provision of this Agreement, which will remain in full force and effect. This Agreement may be executed in one or more counterparts, all of which will be considered one and the same agreement.

9.6 Tax Withholding. The Company may withhold from any amounts payable under this Agreement any federal, state or local taxes that are required to be withheld pursuant to any applicable law or regulation.

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9.7 Code Section 409A. It is intended that this Agreement comply with the requirements of Code Sections 409A(a)(2) through (4) and all regulations issued thereunder. The Agreement shall be interpreted for all purposes in accordance with this intent and may be amended by the Company at any time if such amendment is deemed, in the Company’s sole discretion, necessary to satisfy this intent.

IN WITNESS WHEREOF, the Executive and the Company have executed this Agreement as of the date first above written.

Executive

DOMINION RESOURCES, INC.

By:

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EX-10.40

Exhibit 10.40

DOMINION RESOURCES, INC.

2014 PERFORMANCE GRANT PLAN

1. Purpose. The purpose of the 2014 Performance Grant Plan (the “Plan”) is to set forth the terms of 2014 Performance Grants awarded by Dominion Resources, Inc., a Virginia corporation (the “Company”), pursuant to the Dominion Resources, Inc. 2005 Incentive Compensation Plan and any amendments thereto (the “2005 Incentive Compensation Plan”). This Plan contains the Performance Goals for the awards, the Performance Criteria, the target and maximum amounts payable, and other applicable terms and conditions.

2. Definitions. Capitalized terms used in this Plan not defined in this Section 2 will have the meaning assigned to such terms in the 2005 Incentive Compensation Plan.

a. Cause. For purposes of this Plan, the term “Cause” will have the meaning assigned to that term under a Participant’s Employment Continuity Agreement with the Company, as such Agreement may be amended from time to time.

b. Date of Grant. February 1, 2014.

c. Disability or Disabled. Means a “disability” as defined under Treasury Regulation Section 1.409A-3(i)(4). The Committee, as defined in the 2005 Incentive Compensation Plan document, will determine whether or not a Disability exists and its determination will be conclusive and binding on the Participant.

d. Participant. An officer of the Company or a Dominion Company who receives a Performance Grant on the Date of Grant.

e. Performance Period. The 24-month period beginning on January 1, 2014 and ending on December 31, 2015.

f. Retire or Retirement. For purposes of this Plan, the term Retire or Retirement means a voluntary termination of employment on a date when the Participant is eligible for early or normal retirement benefits under the terms of the Dominion Pension Plan, or would be eligible if any crediting of deemed additional years of age or service applicable to the Participant under the Company’s Benefit Restoration Plan or New Benefit Restoration Plan was applied under the Dominion Pension Plan, as in effect at the time of the determination, unless the Company’s Chief Executive Officer of the Company determines, in his sole discretion, that the Participant’s retirement is detrimental to the Company.

g. Target Amount. The dollar amount designated in the written notice to the Participant communicating the Performance Grant.

3. Performance Grants. A Participant will receive a written notice of the amount designated as the Participant’s Target Amount for the Performance Grant payable under the terms of this Plan. The actual payout may be from 0% to 200% of the Target Amount, depending on the achievement of the Performance Goals.

4. Performance Achievement and Time of Payment. Upon the completion of the Performance Period, the Committee will determine the final Performance Goal achievement of each of the Performance Criteria described in Section 6. The Company will then calculate the final amount of each Participant’s Performance Grant based on such Performance Goal achievement. Except as provided in Sections 7(b) or 8, the Committee will determine the time of payout of the Performance Grants, provided that in no event will payment be made later than March 15, 2016.

5. Forfeiture. Except as provided in Sections 7 and 8, a Participant’s right to payout of a Performance Grant will be forfeited if the Participant’s employment with the Company or a Dominion Company terminates for any reason before the end of the Performance Period.

6. Performance Goals. Payout of Performance Grants will be based on the Performance Goal achievement described in this Section 6 of the Performance Criteria defined in Exhibit A.

a. TSR Performance. Total Shareholder Return Performance (“TSR Performance”) will determine fifty percent (50%) of the Target Amount (“TSR Percentage”). TSR Performance is defined in Exhibit A. The percentage of the TSR Percentage that will be paid out, if any, is based on the following table:

Relative TSR Performance Percentile Ranking	Percentage Payout of TSR Percentage
85th or above		200	%
50th		100	%
25th		50	%
Below 25th		0	%

To the extent that the Company’s Relative TSR Performance ranks in a percentile between the 25^th and 85^th percentile in the table above, then the TSR Percentage payout will be interpolated between the corresponding TSR Percentage payout set forth above. No payment of the TSR Percentage will be made if the Relative TSR Performance is below the 25^th percentile, except that a payment of 25% of the TSR Percentage will be made if the Company’s Relative TSR Performance is below the 25^th percentile but its Absolute TSR Performance is at least 9%. In addition to the foregoing payments, and regardless of the Company’s Relative TSR Performance, if the Company’s Absolute TSR Performance is either (i) at least 10% but less than 15%, then an additional payment of 25% of the TSR Percentage will be made, or (ii) at least 15%, then an additional payment of 50% of the TSR Percentage will be made (in either case, the “Performance Adder”). The Committee may reduce or eliminate payment of the Performance Adder in its sole discretion.

The aggregate payments under this Section 6(a) may not exceed 250% of the TSR Percentage. In addition, the overall percentage payment under the entire Performance Grant may not exceed 200%.

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b. ROIC Performance. Return on Invested Capital Performance (“ROIC Performance”) will determine fifty percent (50%) of the Target Amount (“ROIC Percentage”). ROIC Performance is defined in Exhibit A. The percentage of the ROIC Percentage that will be paid out, if any, is based on the following table:

ROIC Performance	Percentage Payout of ROIC Percentage
7.68% and above		200	%
7.38%		125	%
6.86% - 7.16%		100	%
6.78%		50	%
Below 6.78%		0	%

• To the extent that the Company’s ROIC Performance is greater than 6.78% and less than 6.86%, the ROIC Percentage payout will be interpolated between the applicable Percentage Payout of ROIC Percentage range set forth above.

• To the extent that the Company’s ROIC Performance is greater than 7.16% and less than 7.38%, the ROIC Percentage payout will be interpolated between the applicable Percentage Payout of ROIC Percentage range set forth above.

• To the extent that the Company’s ROIC Performance is greater than 7.38% and less than 7.68%, the ROIC Percentage payout will be interpolated between the applicable Percentage Payout of ROIC Percentage range set forth above.

7. Retirement, Involuntary Termination without Cause, Death or Disability.

a. Retirement or Involuntary Termination without Cause. Except as provided in Section 8, if a Participant Retires during the Performance Period or if a Participant’s employment is involuntarily terminated by the Company or a Dominion Company without Cause during the Performance Period, and in either case the Participant would have been eligible for a payment if the Participant had remained employed until the end of the Performance Period, the Participant will receive a pro-rated payout of the Participant’s Performance Grant equal to the payment the Participant would have received had the Participant remained employed until the end of the Performance Period multiplied by a fraction, the numerator of which is the number of whole months from the Date of Grant to the first day of the month coinciding with or immediately following the date of the Participant’s retirement or termination of employment, and the denominator of which is twenty-three (23). Payment will be made after the end of the Performance Period at the time provided in Section 4 based on the Performance Goal achievement approved by the Committee. If the Participant Retires, however, no payment will be made if the Company’s Chief Executive Officer determines, in his sole discretion, that the Participant’s Retirement is detrimental to the Company.

b. Death or Disability. If, while employed by the Company or a Dominion Company, a Participant dies or becomes Disabled during the Performance Period, the Participant or, in the event of the Participant’s death, the Participant’s Beneficiary will receive a lump sum cash payment equal to the product of (i) and (ii) where:

(i) is the amount that would be paid based on the predicted performance used for determining the compensation cost recognized by the Company for the Participant’s Performance Grant for the latest financial statement filed with the Company’s Annual Report on Form 10-K or Quarterly Report on Form 10-Q immediately prior to the event; and

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(ii) is a fraction, the numerator of which is the number of whole months from the Date of Grant to the first day of the calendar month coinciding with or immediately following the date of the Participant’s death or Disability, and the denominator of which is twenty-three (23).

Payment under this Section 7(b) will be made as soon as administratively feasible (and in any event within sixty (60) days)) after the date of the Participant’s death or Disability, and the Participant shall not have the right to any further payment under this Agreement. In the event of the Participant’s death, payment will be made to the Participant’s designated Beneficiary. If the Participant has not designated a Beneficiary, the Participant’s spouse, if any, and if none the Participant’s estate shall be the Beneficiary.

8. Qualifying Change of Control. Upon a Qualifying Change of Control prior to the end of the Performance Period, provided the Participant has remained continuously employed with Dominion or a Dominion Company from the Date of Grant to the date of the Qualifying Change of Control, the Participant will receive a lump sum cash payment equal to the greater of (i) the Target Amount or (ii) the total payout that would be made at the end of the Performance Period if the predicted performance used for determining the compensation cost recognized by the Company for the Participant’s Performance Grant for the latest financial statement filed with the Company’s Annual Report on Form 10-K or Quarterly Report on Form 10-Q immediately prior to the Qualifying Change of Control was the actual performance for the Performance Period (in either case, the “COC Payout Amount”). Payment will be made on or as soon as administratively feasible following the Qualifying Change of Control date and in no event later than sixty (60) days following the Qualifying Change of Control date. If a Qualifying Change of Control occurs prior to the end of the Performance Period and after a Participant has Retired or been involuntarily terminated without Cause pursuant to Section 7(a) above, then the Participant will receive a pro-rated payout of the Participant’s Performance Grant, equal to the COC Payout Amount multiplied by the fraction set forth in Section 7(a) above, with payment occurring in a cash lump sum on or as soon as administratively feasible (but in any event within sixty (60) days) after the Qualifying Change of Control date. Following any payment under this Section 8, the Participant shall not have the right to any further payment under this Agreement.

9. Termination for Cause. Notwithstanding any provision of this Plan to the contrary, if the Participant’s employment with the Company or a Dominion Company is terminated for Cause (as defined by the Employment Continuity Agreement between the Participant and the Company), the Participant will forfeit all rights to his or her Performance Grant.

10. Clawback of Award Payment.

a. Restatement of Financial Statements. If the Company’s financial statements are required to be restated at any time within a two (2) year period following the end of the Performance Period as a result of fraud or intentional misconduct, the Committee may, in its discretion, based on the facts and circumstances surrounding the restatement, direct the Company to recover all or a portion of the Performance Grant payout from the Participant if the Participant’s conduct directly caused or partially caused the need for the restatement.

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b. Fraudulent or Intentional Misconduct. If the Company determines that the Participant has engaged in fraudulent or intentional misconduct related to or materially affecting the Company’s business operations or the Participant’s duties at the Company, the Committee may, in its discretion, based on the facts and circumstances surrounding the misconduct, direct the Company to withhold payment, or if payment has been made, to recover all or a portion of the Performance Grant payout from the Participant.

c. Recovery of Payout. The Company reserves the right to recover a Performance Grant payout pursuant to this Section 10 by (i) seeking repayment from the Participant; (ii) reducing the amount that would otherwise be payable to the Participant under another Company benefit plan or compensation program to the extent permitted by applicable law; (iii) withholding future annual and long-term incentive awards or salary increases; or (iv) taking any combination of these actions.

d. No Limitation on Remedies. The Company’s right to recover a Performance Grant payout pursuant to this Section 10 shall be in addition to, and not in lieu of, actions the Company may take to remedy or discipline a Participant’s misconduct including, but not limited to, termination of employment or initiation of a legal action for breach of fiduciary duty.

e. Subject to Future Rulemaking. The Performance Grant payout is subject to any claw back policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform Act and Consumer Protection Act and resulting rules issued by the Securities and Exchange Commission or national securities exchanges thereunder and that the Company determines should apply to this Performance Grant Plan.

11. Miscellaneous.

a. Nontransferability. Except as provided in Section 7(b), a Performance Grant is not transferable and is subject to a substantial risk of forfeiture until the end of the Performance Period.

b. No Right to Continued Employment. A Performance Grant does not confer upon a Participant any right with respect to continuance of employment by the Company, nor will it interfere in any way with the right of the Company to terminate a Participant’s employment at any time.

c. Tax Withholding. The Company will withhold Applicable Withholding Taxes from the payout of Performance Grants.

d. Application of Code Section 162(m). Performance Grants are intended to constitute “qualified performance-based compensation” within the meaning of section 1.162-27(e) of the Income Tax Regulations. The Committee will certify the achievement of the Performance Goals described in Section 6. To the maximum extent possible, this Plan will be interpreted and construed in accordance with this subsection 11(d).

e. Negative Discretion. Pursuant to Section 6(c) of the 2005 Incentive Compensation Plan, the Committee retains the authority to exercise negative discretion to reduce payments under this Plan as it deems appropriate.

f. Governing Law. This Plan shall be governed by the laws of the Commonwealth of Virginia, without regard to its choice of law provisions.

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g. Conflicts. In the event of any material conflict between the provisions of the 2005 Incentive Compensation Plan and the provisions of this Plan, the provisions of the 2005 Incentive Compensation Plan will govern.

h. Participant Bound by Plan. By accepting a Performance Grant, a Participant acknowledges receipt of a copy of this Plan and the 2005 Incentive Compensation Plan document and Prospectus, which are accessible on the Company Intranet, and agrees to be bound by all the terms and provisions thereof.

i. Binding Effect. This Plan will be binding upon and inure to the benefit of the legatees, distributes, and personal representatives of Participants and any successors of the Company.

j. Section 409A. This Plan and the Performance Grants hereunder are intended to comply with Section 409A of the Internal Revenue Code of 1986, as amended (“Code Section 409A”), and shall be interpreted to the maximum extent possible in accordance with such intent. To the extent necessary to comply with Code Section 409A, no payment will be made earlier than six months after a Participant’s termination of employment other than for death if the Performance Grant is subject to Code Section 409A and the Participant is a “specified employee” (within the meaning of Code Section 409A(a)(2)(B)(i)).

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EXHIBIT A

DOMINION RESOURCES, INC.

2014 PERFORMANCE GRANT PLAN

PERFORMANCE CRITERIA

Total Shareholder Return

Relative TSR Performance will be measured based on where the Company’s total shareholder return during the Performance Period ranks in relation to the total shareholder returns of the companies that are listed as members of the Philadelphia Stock Exchange Utility Index as of the end of the Performance Period (the “Comparison Companies”). Absolute TSR Performance will be the Company’s total shareholder return on a compounded annual basis for the Performance Period. In general, total shareholder return consists of the difference between the value of a share of common stock at the beginning and end of the Performance Period, plus the value of dividends paid as if reinvested in stock and other appropriate adjustments for such events as stock splits. For purposes of TSR Performance, the total shareholder return of the Company and the Comparison Companies will be calculated using Bloomberg L.P. As soon as practicable after the completion of the Performance Period, the total shareholder returns of the Comparison Companies will be obtained from Bloomberg L.P. and ranked from highest to lowest by the Committee. The Company’s total shareholder return will then be ranked in terms of which percentile it would have placed in among the Comparison Companies.

Return on Invested Capital

Return on Invested Capital (ROIC)

The following terms are used to calculate ROIC for purposes of the 2014 Performance Grant:

ROIC means Total Return divided by Average Invested Capital. Performance will be calculated for the two successive fiscal years within the Performance Period, added together and then divided by two to arrive at an annual average ROIC for the Performance Period.

Total Return means Operating Earnings plus After-tax Interest & Related Charges, all determined for the two successive fiscal years within the Performance Period.

Operating Earnings means operating earnings as disclosed on the Company’s earnings report furnished on Form 8-K for the applicable fiscal year.

Average Invested Capital means the Average Balances for Long & Short-term Debt plus Preferred Equity plus Common Shareholders’ Equity. The Average Balances for a year are calculated by performing the calculation at the end of each month during the fiscal year plus the last month of the prior fiscal year and then averaging those amounts over 13 months. Long and short-term debt shall exclude debt that is non-recourse to Dominion Resources, Inc. (Dominion) or its subsidiaries where Dominion or its subsidiaries has not made an associated investment. Short-term debt shall be net of cash and cash equivalents.

Average Invested Capital will be calculated by excluding (i) accumulated other comprehensive income/(loss) from Common Shareholders’ Equity (as shown on the Company’s financial statements during the Performance Period); (ii) impacts from changes in accounting principles that were not prescribed as of the Date of Grant; and (iii) the effects of incremental impacts from non-operating

i

gains or losses during the Performance Period, as disclosed on the Company’s earnings report furnished on Form 8-K, that were not included in the projection on which the original ROIC calculation was based at the time of the grant.

ii

EX-10.41

Exhibit 10.41

DOMINION RESOURCES, INC.

RESTRICTED STOCK AWARD AGREEMENT

PARTICIPANT «First_Name» «Last_Name»	DATE OF GRANT February 1, 2014	NUMBER OF SHARES OF RESTRICTED STOCK GRANTED «Restricted_Stock_Award_Granted»
PERSONNEL NUMBER «Personnel_»	VESTING DATE February 1, 2017	VESTING SCHEDULE
		Vesting Date February 1, 2017	Percentage 100%

THIS AGREEMENT, effective as of the Date of Grant shown above, between Dominion Resources, Inc., a Virginia Corporation (the “Company”) and the Participant named above is made pursuant and subject to the provisions of the Dominion Resources, Inc. 2005 Incentive Compensation Plan and any amendments thereto (the “Plan”). All terms used in this Agreement that are defined in the Plan have the same meaning given to such terms in the Plan.

1. Award of Stock. Pursuant to the Plan, the Number of Shares of Restricted Stock Granted shown above (the “Restricted Stock”) were awarded to the Participant on the Date of Grant shown above, subject to the terms and conditions of the Plan, and subject further to the terms and conditions set forth in this Agreement.

2. Vesting. Except as provided in Sections 3, 4, 5 or 6, one hundred percent (100%) of the shares of Restricted Stock awarded under this Agreement will vest on the Vesting Date shown above.

3. Forfeiture. Except as provided in Sections 4 or 5, the Participant will forfeit any and all rights in the Restricted Stock if the Participant’s employment with the Company or a Dominion Company terminates for any reason prior to the Vesting Date.

4. Death, Disability, Retirement or Involuntary Termination without Cause. Except as provided in Section 5, if the Participant terminates employment due to death, Disability, or Retirement (as such term is defined in Section 8(e)) before the Vesting Date or if the Participant’s employment is involuntarily terminated by the Company or a Dominion Company without Cause (as defined in the Employment Continuity Agreement between the Participant and the Company) before the Vesting Date, the Participant will become vested in the number of shares of Restricted Stock awarded under this Agreement multiplied by a fraction, the numerator of which is the number of whole months from the Date of Grant to the first day of the month coinciding with or immediately following the date of the Participant’s termination of employment, and the denominator of which is the number of whole months from the Date of Grant to the Vesting Date, rounded

1

down to the nearest whole share. If the Participant Retires, however, the Participant’s Restricted Stock will not vest if the Company’s Chief Executive Officer determines, in his sole discretion, that the Participant’s Retirement is detrimental to the Company. The vesting will occur on the first day of the month coinciding with or immediately following the date of the Participant’s termination of employment due to death, Disability, Retirement, or termination by the Company without Cause. Any shares of Restricted Stock that do not vest in accordance with this Section 4 will be forfeited.

5. Change of Control. Upon a Change of Control prior to the Vesting Date, provided the Participant has remained continuously employed with Dominion or a Dominion Company from the Date of Grant to the date of the Change of Control, the Participant’s rights in the Restricted Stock will become vested as follows:

a. A portion of the Restricted Stock will be immediately vested equal to the number of shares of Restricted Stock awarded under this Agreement multiplied by a fraction, the numerator of which is the number of whole months from the Date of Grant to the Change of Control date, and the denominator of which is the number of whole months from the Date of Grant to the Vesting Date, rounded down to the nearest whole share.

b. Unless previously forfeited, the remaining shares of Restricted Stock will become vested after a Change of Control at the earliest of the following events and in accordance with the terms described in subsections (i) through (iii) below:

(i) Vesting Date. All remaining shares of Restricted Stock will become vested on the Vesting Date.

(ii) Death, Disability or Retirement. If the Participant terminates employment due to death, Disability or Retirement (as defined in Section 8(e)) before the Vesting Date, the Participant will become vested in the remaining shares of Restricted Stock multiplied by a fraction, the numerator of which is the number of whole months from the first day of the month in which the Change of Control occurs to the first day of the month coinciding with or immediately following the Participant’s termination of employment, and the denominator of which is the number of whole months from the first day of the month in which the Change of Control occurs to the Vesting Date, rounded down to the nearest whole share. If the Participant Retires, however, the Participant’s Restricted Stock will not vest if the Company’s Chief Executive Officer, in his sole discretion, determines that the Participant’s Retirement is detrimental to the Company. The vesting will occur on the first day of the month coinciding with or immediately following the Participant’s termination of employment due to death, Disability,

2

or Retirement. Any shares of the Restricted Stock that do not vest in accordance with the terms of this subsection (ii) will be forfeited.

(iii) Involuntary Termination without Cause. All remaining shares of Restricted Stock will become vested upon the Participant’s involuntary termination by the Company or a Dominion Company without Cause before the Vesting Date, or upon the Participant’s Constructive Termination before the Vesting Date, as such terms are defined by the Employment Continuity Agreement between the Participant and the Company.

6. Termination for Cause. Notwithstanding any provision of this Agreement to the contrary, if the Participant’s employment with the Company or a Dominion Company is terminated for Cause (as defined by the Employment Continuity Agreement between the Participant and the Company), the Participant will forfeit all Restricted Stock shares awarded pursuant to this Agreement.

7. Clawback of Award Payment.

a. Restatement of Financial Statements. If the Company’s financial statements are required to be restated at any time within a two (2) year period following the Vesting Date as a result of fraud or intentional misconduct, the Committee may, in its discretion, based on the facts and circumstances surrounding the restatement, direct the Company to withhold issuance of all or a portion of the shares granted pursuant to this Agreement, or if shares have been issued, to recover all or a portion of the shares from the Participant if the Participant’s conduct directly caused or partially caused the need for the restatement.

b. Fraudulent or Intentional Misconduct. If the Company determines that the Participant has engaged in fraudulent or intentional misconduct related to or materially affecting the Company’s business operations or the Participant’s duties at the Company, the Committee may, in its discretion, based on the facts and circumstances surrounding the misconduct, direct the Company to withhold issuance of all or a portion of the shares granted pursuant to this Agreement, or if shares have been issued, to recover all or a portion of the shares from the Participant.

c. Recovery of Payout. The Company reserves the right to recover a Restricted Stock Award payout pursuant to this Section 7 by (i) seeking recovery of the vested shares from the Participant; (ii) reducing the amount that would otherwise be payable to the Participant under another Company benefit plan or compensation program to the extent permitted by applicable law; (iii) withholding future annual and long-term incentive awards or salary increases; or (iv) taking any combination of these actions.

3

d. No Limitation on Remedies. The Company’s right to recover Restricted Stock or issued stock shares pursuant to this Section 7 shall be in addition to, and not in lieu of, actions the Company may take to remedy or discipline a Participant’s misconduct including, but not limited to, termination of employment or initiation of a legal action for breach of fiduciary duty.

e. Subject to Future Rulemaking. The Restricted Stock granted under this Agreement is subject to any claw back policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and resulting rules issued by the Securities and Exchange Commission or national securities exchanges thereunder and that the Company determines should apply to said Restricted Stock.

8. Terms and Conditions.

a. Nontransferability. Except as provided in Sections 4 and 5, the shares of Restricted Stock are not transferable and are subject to a substantial risk of forfeiture until the Vesting Date.

b. Stock Power. As a condition of accepting this award, the Participant hereby assigns and transfers the shares of Restricted Stock granted pursuant to this Agreement to Dominion Resources, Inc., and hereby appoints Dominion Resources Services, Inc. as attorney to transfer such shares on its books.

c. Custody of Shares. The Company will retain custody of the shares of Restricted Stock.

d. Shareholder Rights. The Participant will have the right to receive dividends and will have the right to vote the shares of Restricted Stock awarded under Section 1, both vested and unvested.

e. Retirement. For purposes of this Agreement, the term Retire or Retirement means a voluntary termination when the Participant is eligible for early or normal retirement benefits under the terms of the Dominion Pension Plan, or would be eligible if any crediting of deemed additional years of age or service applicable to the Participant under the Company’s Benefit Restoration Plan or New Benefit Restoration Plan was applied under the Pension Plan, as in effect at the time of the determination, unless the Company’s Chief Executive Officer determines, in his sole discretion, that the Participant’s retirement is detrimental to the Company.

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f. Delivery of Shares.

(i) Share Delivery. As soon as administratively feasible after the Vesting Date or after shares of Restricted Stock have become vested due to the occurrence of an event described in Section 4 or 5, the Company will deliver to the Participant (or in the event of the Participant’s death, the Participant’s Beneficiary) the appropriate number of shares of Company Stock. The Company will also cancel the stock power covering such shares. If the Participant has not designated a Beneficiary, the Participant’s spouse, if any, and if none the Participant’s estate shall be the Beneficiary.

(ii) Withholding of Taxes. No Company Stock will be delivered until the Participant (or the Participant’s Beneficiary) has paid to the Company the amount that must be withheld under federal, state and local income and employment tax laws (the “Applicable Withholding Taxes”) or the Participant and the Company have made satisfactory arrangements for the payment of such taxes. Unless the Participant makes an alternative election, the Company will retain the number of shares of Restricted Stock (valued at their Fair Market Value) required to satisfy the Applicable Withholding Taxes. As an alternative to the Company retaining shares, the Participant or the Participant’s Beneficiary may elect to (i) deliver Mature Shares (valued at their Fair Market Value) or (ii) make a cash payment to satisfy Applicable Withholding Taxes.

g. Fractional Shares. Fractional shares of Company Stock will not be issued.

h. No Right to Continued Employment. This Agreement does not confer upon the Participant any right with respect to continuance of employment by the Company or a Dominion Company, nor shall it interfere in any way with the right of the Company or a Dominion Company to terminate the Participant’s employment at any time.

i. Change in Capital Structure. The number and fair market value of shares of Restricted Stock awarded by this Agreement shall be automatically adjusted as provided in Section 15 of the Plan if the Company has a change in capital structure.

j. Governing Law. This Agreement shall be governed by the laws of the Commonwealth of Virginia, other than its choice of law provisions.

k. Conflicts. In the event of any conflict between the provisions of the Plan and the provisions of this Agreement, the provisions of the Plan shall govern. All references in this Agreement to the Plan shall mean the plan as in effect on the Date of Grant.

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l. Participant Bound by Plan. By accepting this Agreement, Participant hereby acknowledges receipt of a copy of the Prospectus and Plan document accessible on the Company Intranet and agrees to be bound by all the terms and provisions thereof.

m. Binding Effect. This Agreement shall be binding upon and inure to the benefit of the legatees, distributees, and personal representatives of the Participant and any successors of the Company.

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EX-10.42

Exhibit 10.42

DOMINION RESOURCES, INC.

2014 STRATEGIC INITIATIVE PERFORMANCE GRANT

This 2014 Strategic Initiative Performance Grant is awarded by Dominion Resources, Inc., a Virginia corporation (the “Company”) to [NAME], its [TITLE].

1. The Target Amount for your Strategic Initiatives Performance Grant is [AMOUNT] and the Performance Period is January 1, 2014 to December 31, 2014.

2. Upon the completion of the Performance Period, the Committee will determine the final achievement of the Performance Criteria in its sole discretion. The achievement will be expressed as a percentage between 0% and 100%. The Company will then calculate the final amount of your Strategic Initiative Performance Grant payment by multiplying that percentage by your Target Amount. Except as provided in Section 5, the Committee will determine the time of payout of the Strategic Initiative Performance Grant, provided that in no event will payment be made later than March 15, 2015.

3. Except as provided in Section 5, your right to payout of the Strategic Initiative Performance Grant will be forfeited if your employment with the Company terminates for any reason before the end of the Performance Period.

4. Payout of the Strategic Initiative Performance Grant will be based on the progress during the Performance Period toward achievement of the following Performance Criteria:

a. Finalization of the strategic plan for the master limited partnership previously announced by the Company and its role in the long-term financial performance of the Company.

b. Development of long-term enhanced plan for generation and midstream and pipeline opportunities.

5. If, while employed by the Company, you die or become Disabled during the Performance Period, you or, in the event of your death, your Beneficiary will receive a lump sum cash payment equal to the Target Amount times a fraction, the numerator of which is the number of whole months from January 1, 2014 to the first day of the calendar month coinciding with or immediately following the date of your death or Disability, and the denominator of which is twelve (12). Payment will be made as soon as administratively feasible (and in any event within sixty (60) days)) after the date of your death or Disability, and you shall not have the right to any further payment under this Agreement. In the event of your death, payment will be made to your designated Beneficiary. If you have not designated a Beneficiary, your spouse, if any, and if none your estate shall be the Beneficiary.

6. Upon a Qualifying Change of Control prior to the end of the Performance Period, provided you have remained continuously employed with the Company to the date of the Qualifying Change of Control, you will receive a lump sum cash payment equal to the Target Amount. Payment will be made on or as soon as administratively feasible following the Qualifying Change of Control date and in no event later than sixty (60) days following the Qualifying Change of Control date.

1

7. Clawback of Award Payment.

a. Restatement of Financial Statements. If the Company’s financial statements are required to be restated at any time within a two (2) year period following the end of the Performance Period as a result of fraud or intentional misconduct, the Committee may, in its discretion, based on the facts and circumstances surrounding the restatement, direct the Company to recover all or a portion of the Strategic Initiative Performance Grant payout from you if your conduct directly caused or partially caused the need for the restatement.

b. Fraudulent or Intentional Misconduct. If the Company determines that you have engaged in fraudulent or intentional misconduct related to or materially affecting the Company’s business operations or your duties at the Company, the Committee may, in its discretion, based on the facts and circumstances surrounding the misconduct, direct the Company to withhold payment, or if payment has been made, to recover all or a portion of the Performance Grant payout from you.

c. Recovery of Payout. The Company reserves the right to recover the Strategic Initiative Performance Grant payout pursuant to this Section 7 by (i) seeking repayment from you; (ii) reducing the amount that would otherwise be payable to you under another Company benefit plan or compensation program to the extent permitted by applicable law; (iii) withholding future annual and long-term incentive awards or salary increases; or (iv) taking any combination of these actions.

d. No Limitation on Remedies. The Company’s right to recover the Strategic Initiative Performance Grant payout pursuant to this Section 7 shall be in addition to, and not in lieu of, actions the Company may take to remedy or discipline your misconduct including, but not limited to, termination of employment or initiation of a legal action for breach of fiduciary duty.

e. Subject to Future Rulemaking. The Strategic Initiative Performance Grant payout is subject to any claw back policies the Company may adopt in order to conform to the requirements of Section 954 of the Dodd-Frank Wall Street Reform Act and Consumer Protection Act and resulting rules issued by the Securities and Exchange Commission or national securities exchanges thereunder and that the Company determines should apply to this Strategic Initiative Performance Grant.

8. The following provisions will apply to this Strategic Initiatives Performance Grant.

a. Unless defined in this Strategic Initiatives Performance Grant, terms will have the meaning assigned to such terms in the Dominion Resources, Inc. 2005 Incentive Compensation Plan and any amendments thereto.

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b. Except as provided in Section 5 upon your death, this Strategic Initiative Performance Grant is not transferable and is subject to a substantial risk of forfeiture until the end of the Performance Period.

c. This Strategic Initiative Performance Grant does not confer upon you any right with respect to continuance of employment by the Company, nor will it interfere in any way with the right of the Company to terminate your employment at any time.

d. The Company will withhold Applicable Withholding Taxes from the payout of this Strategic Initiative Performance Grant.

e. This Strategic Initiative Performance Grant shall be governed by the laws of the Commonwealth of Virginia, without regard to its choice of law provisions.

f. This Strategic Initiative Performance Grant will be binding upon and inure to the benefit of your legatees, distributes, and personal representatives and any successors of the Company.

g. This Strategic Initiative Performance Grant is intended to comply with Section 409A of the Internal Revenue Code of 1986, as amended (“Code Section 409A”), and shall be interpreted to the maximum extent possible in accordance with such intent. To the extent necessary to comply with Code Section 409A, no payment will be made earlier than six months after your termination of employment other than for death if this Strategic Initiative Performance Grant is subject to Code Section 409A and you are a “specified employee” (within the meaning of Code Section 409A(a)(2)(B)(i)).

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EX-10.43

Exhibit 10.43

Dominion Resources, Inc.

2014 Base Salaries for Named Executive Officers*

The 2014 base salaries for Dominion’s named executive officers are as follows: Thomas F. Farrell II, Chairman, President and Chief Executive Officer—$1,423,038; Mark F. McGettrick, Executive Vice President and Chief Executive Officer—$753,929; Paul D. Koonce, Executive Vice President and Chief Executive Officer— Energy Infrastructure Group—$644,223; David A. Christian, Executive Vice President and Chief Executive Officer—Dominion Generation Group—$644,223; and David A. Heacock, President and Chief Nuclear Officer—Dominion Nuclear—$500,211.

* Effective March 1, 2014

EX-10.44

Exhibit 10.44

Dominion Resources, Inc.

Non-Employee Directors’ Annual Compensation

As of December 31, 2013

Annual Retainer	Amount
Service as Director	$	190,000 ($70,000 cash; $120,000 stock	)
Service as Audit Committee or Compensation, Governance and Nominating Committee Chair	$	17,500
Service as Finance and Risk Oversight Committee Chair	$	15,000
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
	2013 (a)		2012 (b)*			2011 (c)*			2010 (d)*			2009 (e)*
Earnings, as defined:
Income from continuing operations including noncontrolling interest before income tax expense	$	2,704	$	2,265		$	2,262		$	5,178		$	1,936
Distributed income from unconsolidated investees, less equity in earnings		17		(13	)		(23	)		(30	)		(30	)
Fixed charges included in income		930		880			867			835			892
Total earnings, as defined	$	3,651	$	3,132		$	3,106		$	5,983		$	2,798
Fixed charges, as defined:
Interest charges	$	899	$	845		$	818		$	781		$	838
Rental interest factor		31		35			49			54			54
Fixed charges included in income		930		880			867			835			892
Preference security dividend requirement of consolidated subsidiary		25		25			25			28			25
Capitalized Interest		28		24			11			11			13
Interest from discontinued operations		85		80			99			94			96
Total fixed charges, as defined	$	1,068	$	1,009		$	1,002		$	968		$	1,026
Ratio of Earnings to Fixed Charges		3.42		3.10			3.10			6.18			2.73

* Recast to reflect Brayton Point and Kincaid power stations as discontinued operations.

(a) Earnings for the twelve months ended December 31,2013 include $55 million impairment charge related to certain natural gas infrastructure assets; $40 million charge in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2011-2012 test years; $28 million charge associated with our operating expense reduction initiative, primarily reflecting severance pay and other employee related costs; $26 million charge related to the expected early shutdown of certain coal-fired generating units; $29 million charge related to other items; partially offset by $81 million of net gain related to our investments in nuclear decommissioning trust funds; $47 million benefit due to a downward revision in the nuclear decommissioning asset retirement obligations for certain merchant nuclear units that are no longer in service and $29 million net benefit primarily resulting from the sale of Elwood. Excluding the net effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2013.

(b) Earnings for the twelve months ended December 31, 2012 include $438 million of impairment and other charges related 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 the net effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2012.

(c) 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; $43 million impairment of excess emission allowances resulting from a new EPA Air Pollution Rule; $31 million net charge in connection with the Virginia State Corporation 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 a $45 million net charge related to other items; partially offset by a $24 million benefit related to litigation with the Department of Energy for spent nuclear fuel-related costs at our Millstone nuclear power station. Excluding the net effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2011.

(d) Earnings for the twelve months ended December 31, 2010 include a $2.4 billion benefit resulting from the sale of our Appalachian exploration and production (“E&P”) operations—primarily reflecting the gain on the sale partially offset by certain transaction costs and other related charges. Earnings for the period also include a $326 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 the net effect of these items from the calculation would result in a lower ratio of earnings to fixed charges for the twelve months ended December 31, 2010.

(e) Earnings for the twelve months ended December 31, 2009 include a $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; a $455 million impairment charge as a result of the quarterly ceiling test performed on our gas and oil properties under the full cost method of accounting; a $31 million impairment charge related to an equity method investment; and a $10 million net charge related to other items. Earnings for the period also include a $103 million reduction in other operation and maintenance expense due to a downward revision in the nuclear decommissioning asset retirement obligation for a power station that is no longer in service. Excluding the net effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2009.

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,
	2013		2012		2011		2010		2009
Earnings, as defined:
Income from continuing operations before income tax expense	$	1,797	$	1,703	$	1,362	$	1,394	$	503
Fixed charges included in income		401		418		361		385		392
Total earnings, as defined	$	2,198	$	2,121	$	1,723	$	1,779	$	895
Fixed charges, as defined:
Interest charges	$	388	$	404	$	346	$	368	$	376
Rental interest factor		13		14		15		17		16
Total fixed charges, as defined	$	401	$	418	$	361	$	385	$	392
Ratio of Earnings to Fixed Charges		5.48		5.07		4.77		4.62		2.28

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,
	2013		2012		2011		2010		2009
Earnings, as defined:
Income from continuing operations before income tax expense	$	1,797	$	1,703	$	1,362	$	1,394	$	503
Fixed charges included in income		401		418		361		385		392
Total earnings, as defined	$	2,198	$	2,121	$	1,723	$	1,779	$	895
Fixed charges, as defined:
Interest charges	$	388	$	404	$	346	$	368	$	376
Rental interest factor		13		14		15		17		16
Fixed charges included in income		401		418		361		385		392
Preference security dividend requirement		26		27		27		27		24
Total fixed charges, as defined	$	427	$	445	$	388	$	412	$	416
Ratio of Earnings to Fixed Charges and Preferred Dividends		5.15		4.77		4.44		4.32		2.15

EX-21

Exhibit 21

Dominion Resources, Inc.

Subsidiaries of the Registrant

As of February 15, 2014

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 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 Energy Marketing, Inc.	Delaware	Dominion Energy Marketing, Inc.
Dominion Nuclear Connecticut, Inc.	Delaware	Dominion Nuclear Connecticut, Inc.
Dominion Energy Manchester Street, Inc.	Virginia	Dominion Energy Manchester Street, 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 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, Inc.	Virginia	Dominion Solar Holdings, Inc.
Azalea Solar, LLC	Delaware	Azalea Solar, LLC
Dominion Solar Construction and Maintenance, LLC	Virginia	Dominion Solar Construction and Maintenance, LLC
Indy Solar Development, LLC	Delaware	Indy Solar Development, LLC
Indy Solar I, LLC	Delaware	Indy Solar I, LLC
Indy Solar II, LLC	Delaware	Indy Solar II, LLC
Indy Solar III, LLC	Delaware	Indy Solar III, LLC
Somers Solar Center, LLC	Delaware	Somers Solar Center, LLC
Dominion Solar Gen-Tie, LLC	Virginia	Dominion Solar Gen-Tie, 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 VirginiaWind Development, LLC	Virginia	Dominion VirginiaWind Development, LLC
Dominion Fowler Ridge Wind, LLC	Virginia	Dominion Fowler Ridge Wind, LLC
Dominion Wind Development, LLC	Virginia	Dominion Wind Development, 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. DVI
Tredegar Solar Fund I, LLC	Delaware	Tredegar Solar Fund I, LLC
Dominion Field Services, Inc.	Delaware	Dominion Field Services, Inc.
Dominion Gas Holdings, LLC	Virginia	Dominion Gas Holdings, LLC
Dominion Iroquois, Inc.	Delaware	Dominion Iroquois, 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.
The East Ohio Gas Company	Ohio	Dominion East Ohio
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 High Voltage Holdings, Inc.	Virginia	Dominion High Voltage Holdings, Inc.
Dominion Investments, Inc.	Virginia	Dominion Investments, 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 &	Delaware	Dominion Oklahoma Texas Exploration &
Production, Inc		Production, Inc.
Dominion Privatization Holdings, Inc.	Virginia	Dominion Privatization Holdings, Inc.
Dominion Privatization Florida, LLC	Virginia	Dominion Privatization Florida, LLC
Dominion Privatization Texas, LLC	Virginia	Dominion Privatization Texas, LLC
Dominion Privatization South Carolina, LLC	Virginia	Dominion Privatization South Carolina, LLC
Dominion Privatization Georgia, LLC	Virginia	Dominion Privatization Georgia, LLC
Dominion Privatization Kentucky, LLC	Virginia	Dominion Privatization Kentucky, LLC
Dominion Products and Services, Inc.	Delaware	Dominion Products and Services, Inc.
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 Natrium Holdings, Inc.	Delaware	Dominion Natrium Holdings, Inc.
Hope Gas, Inc.	West Virginia	Dominion Hope
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. 333-158519 and 333-179213 on Forms S-3, Registration Statement No. 333-120339 on Form S-4, and Registration Statement Nos. 333-163805, 333-189578, 333-149993, 333-130570, 333-189581, 333-156027, 333-130566, 333-189580, 333-124257, 333-124256, 333-149989, 333-85094, 333-95795, 333-189579, 333-49725, 333-18391, and 333-02733 on Forms S-8 of our reports dated February 27, 2014, 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, 2013.

We consent to the incorporation by reference in Registration Statement No. 333-178772 on Form S-3 of our report dated February 27, 2014, 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, 2013.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 27, 2014

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 27, 2014	/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 27, 2014	/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 27, 2014	/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 27, 2014	/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, 2013 (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, 2013 and for the period then ended.

/s/ Thomas F. Farrell II

Thomas F. Farrell II

President and Chief Executive Officer

February 27, 2014

/s/ Mark F. McGettrick

Mark F. McGettrick

Executive Vice President and Chief Financial Officer

February 27, 2014

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, 2013 (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, 2013 and for the period then ended.

/s/ Thomas F. Farrell II

Thomas F. Farrell II

Chief Executive Officer

February 27, 2014

/s/ Mark F. McGettrick

Mark F. McGettrick

Executive Vice President and Chief Financial Officer

February 27, 2014

EX-99.1

Exhibit 99.1

Towers Watson Energy Services Executive Survey participants:

AEI Services	Exelon	Salt River Project
AES	FirstEnergy	SCANA
Allete	GenOn Energy	Sempra Energy
Alliant Energy	Iberdrola Renewables	Southern Company Services
Ameren	Idaho Power	Southern Union Company
American Electric Power	Integrys Energy Group	South Jersey Gas
ATC Management	IPR – GDF SUEZ North America	Spectra Energy
Atmos Energy	Kinder Morgan	STP Nuclear Operating
Avista	LG&E and KU Energy	Targa Resources
Babcock Power	Lower Colorado River Authority	TECO Energy
Babcock & Wilcox	MDU Resources	Tennessee Valley Authority
BG US Services	MGE Energy	TransCanada
Black Hills Power and Light	MidAmerican Energy	UGI
Capital Power Corporation	New York Power Authority	UIL Holdings
CenterPoint Energy	Nextera Energy	UniSource Energy
CH Energy Group	Northeast Utilities	Untill
Cheniere Energy	Northwestern Energy	URENCO USA
CMS Energy	NRG Energy	Vectren
Colorado Springs Utilities	NSTAR	Westar Energy
Consolidated Edison	NVEnergy	Williams Companies
Crosstex Energy	NW Natural	Wisconsin Energy
Dominion Resources	OGE Energy	Wolf Creek Nuclear
DTE Energy	Oglethorpe Power	Xcel Energy
Duke Energy	Ohio Valley Electric
Dynegy	Omaha Public Power
Edison International	Pacific Gas & Electric
ElectriCities of North Carolina	Pepco Holdings
El Paso Corporation	Pinnacle West Capital
El Paso Electric	PNM Resources
Enbridge Energy	Portland General Electric
Energen	PPL
Energy Future Holdings	Primary Energy Recycling
Energy Northwest	Progress Energy
Entergy	Proliance Holdings
Enterprise Products Partners	Public Service Enterprise Group
EQT Corporation	Pugent Energy

XML

Dispositions (Tables)

12 Months Ended

Dec. 31, 2013

Brayton Point and Kincaid

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 Brayton Point and Kincaid, which are reported as discontinued operations in Dominion's Consolidated Statements of Income:

Year Ended December 31,	2013				2012				2011
(millions)
Operating revenue	$	304			$	258			$	380
Loss before income taxes	(135		)	(1)	(1,768		)	(2)	(57		)

(1) Includes $64 million of charges related to the defeasance of Brayton Point debt and the early redemption of Kincaid debt in 2013. See Note 17 for more information.

(2) Includes a long-lived asset impairment charge of $1.6 billion.

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 reported as discontinued operations in Dominion's Consolidated Statements of Income:

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

(1) Includes long-lived asset impairment charges of $55 million in 2011.

XML

Quarterly Financial and Common Stock Data (Unaudited) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended	3 Months Ended					12 Months Ended	3 Months Ended	12 Months Ended					3 Months Ended	12 Months Ended
	Dec. 31, 2013	Jun. 30, 2013 Brayton Point and Kincaid	Sep. 30, 2012 Kewaunee	Dec. 31, 2013 Virginia Electric and Power Company	Jun. 30, 2012 Virginia Electric and Power Company	Jun. 30, 2013 Dominion Energy	Dec. 31, 2013 Dominion Energy	Jun. 30, 2013 Dominion Energy Brayton Point and Kincaid	Dec. 31, 2011 Dominion Generation	Dec. 31, 2013 Dominion Generation Brayton Point and Kincaid	Dec. 31, 2011 Dominion Generation Brayton Point and Kincaid	Dec. 31, 2012 Dominion Generation Kewaunee	Dec. 31, 2013 Dominion Generation Virginia Electric and Power Company	Dec. 31, 2012 Brayton Point Kincaid And Elwood Power Stations Dominion Generation	Dec. 31, 2012 Brayton Point Kincaid And Elwood Power Stations Dominion Generation
Condensed Financial Statements, Captions [Line Items]
Loss before income taxes		$ (70)								$ (135)	$ (57)	$ (467)			$ (1,700)
Loss from operations after tax							109	57		8
Impairment charge after tax						33	33
Loss from producer services business after tax						24	76
Impairment charge	1,600									48				1,000
Impairment and other charges			281
Restoration costs net of tax				28									28
Asset impairment, net of tax					$ 42				$ 139

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
	Jan. 31, 2012 Agreement	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Dominion Direct, Employee Stock Awards, Employee Savings Plans, Director Stock Compensation Plans, and Contingent Convertible Senior Notes	Dec. 31, 2013 Stock-Based Awards	Dec. 31, 2013 Restricted Stock	Dec. 31, 2012 Restricted Stock	Dec. 31, 2011 Restricted Stock	Dec. 31, 2013 Goal-Based Stock Performance_Metric	Dec. 31, 2012 Goal-Based Stock Officer	Dec. 31, 2011 Goal-Based Stock Officer	Dec. 31, 2013 Cash-Based Performance Grant Performance_Metric	Dec. 31, 2012 Cash-Based Performance Grant Performance_Metric	Dec. 31, 2007 Cash-Based Performance Grant	Feb. 28, 2013 February 2011 Awards	Feb. 28, 2012 February 2011 Awards	Feb. 28, 2011 February 2011 Awards	Feb. 28, 2010 February 2011 Awards	Dec. 31, 2013 February 2012 Awards	Dec. 31, 2013 February 2012 Awards	Dec. 31, 2013 February 2013 Awards	Dec. 31, 2013 Dominion Direct, employee savings plans
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock shares issued		5,400,000																					4,700,000
Cash proceeds		$ 278	$ 265	$ 38
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		317
Shares reserved and available for issuance		22,500,000			48,000,000
Shares were available for future grants						32,000,000
Compensation cost related to stock-based compensation		31	25	39
Tax benefit from stock awards and stock options exercised		11	8	13
Tax benefits from the vesting of restricted stock awards		1	10	2
Cash proceeds from the exercise of stock options			19	38
Vesting period							3 years			3 years
Unrecognized compensation cost related to nonvested awards							21
Expected weighted-average period recognized for the unrecognized compensation cost							1 year 9 months 6 days
Fair value of restricted stock awards that vested							20	30	28
Number of performance metrics										2			2	2
Performance metrics period										2 years
Shares issued minimum percentage										0.00%
Shares issued maximum percentage										200.00%
Stock awards granted											3,000	9,000
Number of shares converted to one class to another									168,000	1,000	2,000	15,000
Targeted shares expected to be issued										5,000
Cash-based performance grants minimum															0.00%
Cash-based performance grants maximum															200.00%
Cash based performance grant actual payout																2	6	6	14	8
Cash-based performance grants																8	20					13
Cash based performance grant liability accrued																					4	6
Cash based performance grants, total expected award																					$ 12

XML

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2013

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,	2013			2012			2013			2012
(millions, except percentages)
Changes in benefit obligation:
Benefit obligation at beginning of year	$	6,125		$	4,981		$	1,719		$	1,493
Service cost	131			116			43			44
Interest cost	271			268			73			79
Benefits paid	(229		)	(208		)	(75		)	(88		)
Actuarial (gains) losses during the year	(650		)	967			(170		)	191
Plan amendments(1)	1			1			(220		)	1
Settlements and curtailments(2)	(24		)	—			(16		)	(6		)
Special termination benefits	—			—			1			—
Medicare Part D reimbursement	—			—			5			5
Benefit obligation at end of year	$	5,625		$	6,125		$	1,360		$	1,719
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	5,553		$	5,145		$	1,156		$	1,042
Actual return on plan assets	781			611			178			132
Employer contributions	8			5			12			16
Benefits paid	(229		)	(208		)	(31		)	(34		)
Fair value of plan assets at end of year	$	6,113		$	5,553		$	1,315		$	1,156
Funded status at end of year	$	488		$	(572	)	$	(45	)	$	(563	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	913		$	701		$	29		$	1
Other current liabilities	(15		)	(2		)	(3		)	(4		)
Noncurrent pension and other postretirement benefit liabilities	(410		)	(1,271		)	(71		)	(560		)
Net amount recognized	$	488		$	(572	)	$	(45	)	$	(563	)
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate(3)	5.20%/5.30%			4.40		%	5.00%/5.10%			4.40		%
Weighted average rate of increase for compensation	4.21		%	4.21		%	4.22		%	4.22		%

(1) Relates to a plan amendment that changed medical coverage for certain Medicare-eligible retirees.

(2) 2013 amounts relate primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor.

(3) Pension rates are 5.20% for the gas union plans and 5.30% for the nonunion and other union plans. OPEB rates are 5.00% for the gas union plans and 5.10% for the nonunion and other union plans.

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,	2013		2012		2013		2012
(millions)
Benefit obligation	$	4,978	$	5,462	$	1,233	$	1,591
Fair value of plan assets	4,553		4,189		1,158		1,027

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,	2013		2012
(millions)
Accumulated benefit obligation	$	114	$	4,850
Fair value of plan assets	—		4,189

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)
2014	$	264	$	91
2015	269		93
2016	283		96
2017	300		98
2018	319		100
2019-2023	1,868		507

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,	2013								2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	53	$	126	—		$	179	—		$	195	—		$	195
U.S. equity:
Large Cap	1,220		—		—		1,220		927		104		—		1,031
Other	514		—		—		514		425		99		—		524
Non-U.S. equity:
Large Cap	308		—		—		308		313		68		—		381
Other	391		—		—		391		228		167		—		395
Common/collective trust funds	—		1,387		—		1,387		—		—		—		—
Fixed income:
Corporate debt instruments	43		451		—		494		27		1,026		—		1,053
U.S. Treasury securities and agency debentures	2		229		—		231		331		304		—		635
State and municipal	69		107		—		176		1		71		—		72
Other securities	7		50		—		57		5		43		—		48
Real estate:
REITs	32		—		—		32		29		—		—		29
Partnerships	—		—		227		227		—		—		321		321
Other alternative investments:
Private equity	—		—		530		530		—		—		456		456
Debt	—		—		180		180		—		—		192		192
Hedge funds	—		—		187		187		—		—		221		221
Total	$	2,639	$	2,350	$	1,124	$	6,113	$	2,286	$	2,077	$	1,190	$	5,553

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,	2013								2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	3	$	14	$	—	$	17	$	—	$	13	$	—	$	13
U.S. equity:
Large Cap	472		—		—		472		378		5		—		383
Other	26		—		—		26		21		45		—		66
Non-U.S. equity:
Large Cap	111		—		—		111		93		3		—		96
Other	20		—		—		20		11		8		—		19
Common/collective trust funds	—		502		—		502		—		—		—		—
Fixed income:
Corporate debt instruments	2		23		—		25		1		160		—		161
U.S. Treasury securities and agency debentures	—		12		—		12		16		266		—		282
State and municipal	4		5		—		9		—		9		—		9
Other securities	—		3		—		3		—		2		—		2
Real estate:
REITs	2		—		—		2		1		—		—		1
Partnerships	—		—		19		19		—		—		24		24
Other alternative investments:
Private equity	—		—		60		60		—		—		58		58
Debt	—		—		27		27		—		—		31		31
Hedge funds	—		—		10		10		—		—		11		11
Total	$	640	$	559	$	116	$	1,315	$	521	$	511	$	124	$	1,156

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, 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
Actual return on plan assets:
Relating to assets still held at the reporting date	15			98			32			21			166			(2		)	6			3			1			8
Relating to assets sold during the period	(36		)	(48		)	(34		)	(4		)	(122		)	1			3			—			1			5
Purchases	6			115			32			—			153			1			7			2			—			10
Sales	(79		)	(91		)	(42		)	(51		)	(263		)	(5		)	(14		)	(9		)	(3		)	(31		)
Balance at December 31, 2013	$	227		$	530		$	180		$	187		$	1,124		$	19		$	60		$	27		$	10		$	116

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,	2013			2012			2011			2013			2012			2011
(millions, except percentages)
Service cost	$	131		$	116		$	108		$	43		$	44		$	48
Interest cost	271			268			258			73			79			94
Expected return on plan assets	(462		)	(430		)	(440		)	(92		)	(79		)	(79		)
Amortization of prior service (credit) cost	3			3			3			(15		)	(13		)	(13		)
Amortization of net actuarial loss	165			132			96			7			6			12
Settlements and curtailments(1)	(2		)	—			—			(15		)	(4		)	1
Special termination benefits	—			—			—			1			—			—
Net periodic benefit cost	$	106		$	89		$	25		$	2		$	33		$	63
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	(968	)	$	786		$	534		$	(255	)	$	139		$	(157	)
Prior service (credit) cost	1			—			—			(215		)	1			(70		)
Settlements and curtailments(1)	(22		)	—			—			(7		)	(2		)	(1		)
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss	(165		)	(132		)	(96		)	(7		)	(6		)	(12		)
Amortization of prior service credit (cost)	(3		)	(3		)	(3		)	15			13			13
Total recognized in other comprehensive income and regulatory assets and liabilities	$	(1,157	)	$	651		$	435		$	(469	)	$	145		$	(227	)
Significant assumptions used to determine periodic cost:
Discount rate	4.40% - 4.80%			5.50		%	5.90		%	4.40% - 4.80%			5.50		%	5.90		%
Expected long-term rate of return on plan assets	8.50		%	8.50		%	8.50		%	7.75		%	7.75		%	7.75		%
Weighted average rate of increase for compensation	4.21		%	4.21		%	4.61		%	4.22		%	4.22		%	4.62		%
Healthcare cost trend rate(2)										7.00		%	7.00		%	7.00		%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(2)										4.60		%	4.60		%	4.60		%
Year that the rate reaches the ultimate trend rate(2)										2062			2061			2060

(1) 2013 amount relates primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor.

(2) 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 (credit) cost are as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2013		2012		2013			2012
(millions)
Net actuarial (gain) loss	$	1,709	$	2,865	$	(40	)	$	229
Prior service (credit) cost	10		11		(271		)	(71		)
Total(1)	$	1,719	$	2,876	$	(311	)	$	158

(1) As of December 31, 2013, of the $1.7 billion and $(311) million related to pension benefits and other postretirement benefits, $1.0 billion and $(156) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. 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.

Components of AOCI and regulatory assets and liabilities that are expected to be amortized as components of periodic benefit cost in 2014

The following table provides the components of AOCI and regulatory assets and liabilities as of December 31, 2013 that are expected to be amortized as components of periodic benefit cost in 2014:

	Pension Benefits		Other Postretirement Benefits
(millions)
Net actuarial loss	$	112	$	2
Prior service (credit) cost	3		(28		)

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 net periodic cost for 2014	$	16	$	(18	)
Effect on other postretirement benefit obligation at December 31, 2013	140		(118		)

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities

Regulatory assets and liabilities include the following:

At December 31,	2013		2012
(millions)
Dominion
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	89	$	55
Unrecovered gas costs(2)	50		59
Virginia sales taxes(3)	46		37
Derivatives(4)	16		—
Plant retirement(5)	1		25
Other	15		27
Regulatory assets-current(6)	217		203
Unrecognized pension and other postretirement benefit costs(7)	706		1,210
Deferred rate adjustment clause costs(1)	287		173
Income taxes recoverable through future rates(8)	155		140
Derivatives(4)	16		105
Other postretirement benefit costs(9)	12		21
Plant retirement(5)	10		11
Other	42		57
Regulatory assets-non-current	1,228		1,717
Total regulatory assets	$	1,445	$	1,920
Regulatory liabilities:
PIPP(10)	$	76	$	100
Deferred cost of fuel used in electric generation(11)	24		7
Other	28		29
Regulatory liabilities-current(12)	128		136
Provision for future cost of removal and AROs(13)	1,028		985
Decommissioning trust(14)	693		501
Unrecognized pension and other postretirement benefit costs(7)	174		2
Deferred cost of fuel used in electric generation(11)	90		13
Other	16		13
Regulatory liabilities-non-current	2,001		1,514
Total regulatory liabilities	$	2,129	$	1,650
Virginia Power
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	62	$	51
Virginia sales taxes(3)	46		37
Derivatives(4)	16		—
Plant retirement(5)	1		25
Other	3		6
Regulatory assets-current	128		119
Deferred rate adjustment clause costs(1)	227		127
Income taxes recoverable through future rates(8)	124		110
Derivatives(4)	16		105
Plant retirement(5)	10		11
Other	40		43
Regulatory assets-non-current	417		396
Total regulatory assets	$	545	$	515
Regulatory liabilities:
Deferred cost of fuel used in electric generation(11)	$	24	$	7
Other	17		25
Regulatory liabilities-current	41		32
Provision for future cost of removal(13)	807		763
Decommissioning trust(14)	693		501

Deferred cost of fuel used in electric generation(11)	90		14
Other	7		7
Regulatory liabilities-non-current	1,597		1,285
Total regulatory liabilities	$	1,638	$	1,317

(1) Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for more information.

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

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

(6) Current regulatory assets are presented in other current assets in Dominion's Consolidated Balance Sheets.

(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) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power's generation operations. For 2013, amount includes approximately $5 million related to DOE claims. See Note 13 for more information.

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

(13) 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.

(14) 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.

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Employee Benefit Plans (Accumulated Benefit Obligation in Excess of Plan Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
General Discussion of Pension and Other Postretirement Benefits [Abstract]
Accumulated benefit obligation	$ 114	$ 4,850
Fair value of plan assets	$ 0	$ 4,189

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Income Taxes Income Taxes (Schedule of Income Tax Expense from Discontinued Operations) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current:
Federal	$ (274)	$ (248)	$ (41)
State	(41)	(6)	(17)
Total current benefit	(315)	(254)	(58)
Deferred:
Federal	232	(368)	10
State	40	(70)	15
Total deferred expense (benefit)	272	(438)	25
Total income tax benefit	$ (43)	$ (692)	$ (33)

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$ 1,190	$ 1,285	$ 1,278
Actual return on plan assets:
Relating to assets still held at the reporting date	166	105	128
Relating to assets sold during the period	(122)	(62)	(67)
Purchases	153	129	215
Sales	(263)	(267)	(269)
Fair value of plan assets at end of year	1,124	1,190	1,285
Pension Benefits | Real estate:
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	321	304	271
Actual return on plan assets:
Relating to assets still held at the reporting date	15	21	38
Relating to assets sold during the period	(36)	(8)	(8)
Purchases	6	35	57
Sales	(79)	(31)	(54)
Fair value of plan assets at end of year	227	321	304
Pension Benefits | Private equity
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	456	448	400
Actual return on plan assets:
Relating to assets still held at the reporting date	98	46	70
Relating to assets sold during the period	(48)	(41)	(34)
Purchases	115	79	76
Sales	(91)	(76)	(64)
Fair value of plan assets at end of year	530	456	448
Pension Benefits | Debt
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	192	243	262
Actual return on plan assets:
Relating to assets still held at the reporting date	32	17	10
Relating to assets sold during the period	(34)	(11)	(10)
Purchases	32	15	34
Sales	(42)	(72)	(53)
Fair value of plan assets at end of year	180	192	243
Pension Benefits | Hedge funds
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	221	290	345
Actual return on plan assets:
Relating to assets still held at the reporting date	21	21	10
Relating to assets sold during the period	(4)	(2)	(15)
Purchases	0	0	48
Sales	(51)	(88)	(98)
Fair value of plan assets at end of year	187	221	290
Other Postretirement Plans
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	124	137	140
Actual return on plan assets:
Relating to assets still held at the reporting date	8	9	15
Relating to assets sold during the period	5	(1)	(6)
Purchases	10	9	16
Sales	(31)	(30)	(28)
Fair value of plan assets at end of year	116	124	137
Other Postretirement Plans | Real estate:
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	24	24	22
Actual return on plan assets:
Relating to assets still held at the reporting date	(2)	1	3
Relating to assets sold during the period	1	0	0
Purchases	1	2	3
Sales	(5)	(3)	(4)
Fair value of plan assets at end of year	19	24	24
Other Postretirement Plans | Private equity
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	58	63	61
Actual return on plan assets:
Relating to assets still held at the reporting date	6	3	11
Relating to assets sold during the period	3	(1)	(4)
Purchases	7	6	8
Sales	(14)	(13)	(13)
Fair value of plan assets at end of year	60	58	63
Other Postretirement Plans | Debt
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	31	36	40
Actual return on plan assets:
Relating to assets still held at the reporting date	3	4	1
Relating to assets sold during the period	0	0	(1)
Purchases	2	1	3
Sales	(9)	(10)	(7)
Fair value of plan assets at end of year	27	31	36
Other Postretirement Plans | Hedge funds
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	11	14	17
Actual return on plan assets:
Relating to assets still held at the reporting date	1	1	0
Relating to assets sold during the period	1	0	(1)
Purchases	0	0	2
Sales	(3)	(4)	(4)
Fair value of plan assets at end of year	$ 10	$ 11	$ 14

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Loss Contingencies [Line Items]

Nuclear Insurance

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

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

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

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, 2013 are as follows:

	2014		2015		2016		2017		2018		Thereafter		Total
(millions)
Dominion	$	63	$	60	$	51	$	43	$	37	$	87	$	341
Virginia Power	$	27	$	26	$	21	$	17	$	14	$	27	$	132

Subsidiary guarantees

At December 31, 2013, Dominion had issued the following subsidiary guarantees:

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	27	$	27
Commodity transactions(3)	3,158		403
Nuclear obligations(4)	232		68
Cove Point(5)	335		—
Other(6)	669		108
Total	$	4,421	$	606

(1) Represents the estimated portion of the guarantee's stated limit that is utilized as of December 31, 2013 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

(2) Guarantee of debt of a DEI subsidiary. In the event of default by the subsidiary, Dominion would be obligated to repay such amounts.

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

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

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

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

Virginia Electric and Power Company

Loss Contingencies [Line Items]

Long-term Purchase Commitment

At December 31, 2013, 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:

	2014		2015		2016		2017		2018		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	336	$	316	$	253	$	159	$	104	$	163	$	1,331

(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, 2013, the present value of Virginia Power's total commitment for capacity payments is $1.1 billion. Capacity payments totaled $345 million, $337 million, and $338 million, and energy payments totaled $236 million, $214 million, and $275 million for 2013, 2012 and 2011, respectively.

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Derivatives and Hedge Accounting Activities (Schedule of Offsetting Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 1,100		$ 650
Gross Amounts Offset in the Consolidated Balance Sheet	0	[1]	0	[1]
Total derivatives, not subject to a master netting or similar arrangement	2		11
Derivative liabilities	1,102	[1]	661	[1]
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	568		466
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Paid	402		63
Net Amounts	130		121
Derivative liabilities	828		510
Derivative Liability, Noncurrent	2		4
Current Liabilities
Offsetting Liabilities [Line Items]
Derivative liabilities	828		510
Non Current Derivative Liabilities
Offsetting Liabilities [Line Items]
Derivative Liability, Noncurrent	274		151
Interest rate | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0		66
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	0		19
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Paid	0		0
Net Amounts	0		47
Commodity | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	262		191
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	63		97
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Paid	69		20
Net Amounts	130		74
Commodity | Exchange
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	838		393
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	505		350
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Paid	333		43
Net Amounts	0		0
Virginia Electric and Power Company
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	12		34
Gross Amounts Offset in the Consolidated Balance Sheet	0	[1]	0	[1]
Total derivatives, not subject to a master netting or similar arrangement	0		0
Derivative liabilities	12	[1]	34	[1]
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	4		3
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Paid	7		2
Net Amounts	1		29
Derivative liabilities	12		33
Virginia Electric and Power Company | Current Liabilities
Offsetting Liabilities [Line Items]
Derivative liabilities	12		33
Virginia Electric and Power Company | Non Current Derivative Liabilities
Offsetting Liabilities [Line Items]
Derivative Liability, Noncurrent			1
Virginia Electric and Power Company | Interest rate | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0		25
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Paid	0		0
Net Amounts	0		25
Virginia Electric and Power Company | Commodity | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	12		7
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	4		3
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Paid	7		0
Net Amounts	1		4
Virginia Electric and Power Company | Commodity | Exchange
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0		2
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Paid	0		2
Net Amounts	$ 0		$ 0

[1] At December 31, 2013, the total derivative liability balance contains $828 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet, and $274 million of noncurrent liabilities, which is presented in the other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $510 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet and $151 million of noncurrent liabilities, which is presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet.

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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, 2013		Dec. 31, 2012
Short term Debt [Line Items]
Facility Limit	$ 3,500,000,000		$ 3,500,000,000
Outstanding Commercial Paper	1,927,000,000	[1]	2,412,000,000	[1]
Outstanding Letters of Credit	11,000,000		26,000,000
Facility Capacity Available	1,562,000,000		1,062,000,000
Weighted-average interest rates of the outstanding commercial paper	0.33%		0.49%
Virginia Electric and Power Company
Short term Debt [Line Items]
Facility Limit	1,250,000,000		1,250,000,000
Outstanding Commercial Paper	842,000,000	[2]	992,000,000	[2]
Outstanding Letters of Credit	1,000,000		2,000,000
Facility Capacity Available	407,000,000		256,000,000
Weighted-average interest rates of the outstanding commercial paper	0.33%		0.47%
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	1,927,000,000	[3]	2,412,000,000	[3]
Outstanding Letters of Credit	0	[3]	0	[3]
Facility Capacity Available	1,073,000,000	[3]	588,000,000	[3]
Credit facility, to support letters of credit	1,500,000,000.0
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	842,000,000	[4]	992,000,000	[4]
Outstanding Letters of Credit	0	[4]	0	[4]
Facility Capacity Available	158,000,000	[4]	8,000,000	[4]
Credit facility, to support letters of credit	1,500,000,000.0
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	11,000,000	[5]	26,000,000	[5]
Facility Capacity Available	489,000,000	[5]	474,000,000	[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	1,000,000	[6]	2,000,000	[6]
Facility Capacity Available	249,000,000	[6]	248,000,000	[6]
Tax-Exempt Financings | Virginia Electric and Power Company
Short term Debt [Line Items]
Variable rate tax-exempt financings	$ 119,000,000

[1] The weighted-average interest rates of the outstanding commercial paper supported by Dominion's credit facilities were 0.33% and 0.49% at December 31, 2013 and 2012, respectively.

[2] The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 0.33% and 0.47% at December 31, 2013 and 2012, respectively.

[3] Effective September 2013, the maturity date was extended from September 2017 to September 2018. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.

[4] Effective September 2013, the maturity date was extended from September 2017 to September 2018. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power's current sub-limit under this credit facility can be increased or decreased multiple times per year.

[5] Effective September 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

[6] Effective September 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power's current sub-limit under this credit facility can be increased or decreased multiple times per year.

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

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,	2013		2012
(millions)
Dominion
Utility:
Generation	$	14,018	$	13,707
Transmission	8,686		7,799
Distribution	11,714		11,071
Storage	2,190		2,137
Nuclear fuel	1,375		1,277
Gas gathering and processing	787		803
General and other	812		803
Other-including plant under construction	3,261		2,232
Total utility	42,843		39,829
Nonutility:
Merchant generation-nuclear	1,153		1,163
Merchant generation-other(1)	1,328		1,289
Nuclear fuel	770		775
Other-including plant under construction	875		1,265
Total nonutility	4,126		4,492
Total property, plant and equipment	$	46,969	$	44,321
Virginia Power
Utility:
Generation	$	14,018	$	13,707
Transmission	4,959		4,261
Distribution	9,103		8,701
Nuclear fuel	1,375		1,277
General and other	668		659
Other-including plant under construction	2,719		2,017
Total utility	32,842		30,622
Nonutility-other	6		9
Total property, plant and equipment	$	32,848	$	30,631

(1) 2012 amount includes $957 million due to consolidation of a VIE. See Note 15 for further information.

Share of Jointly-Owned Power Stations

Dominion's and Virginia Power's proportionate share of jointly-owned power stations at December 31, 2013 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	$	1,038		$	2,486		$	568		$	1,007
Accumulated depreciation	(536		)	(1,109		)	(199		)	(262		)
Nuclear fuel	—			597			—			388
Accumulated amortization of nuclear fuel	—			(434		)	—			(283		)
Plant under construction	23			76			6			69

(1) Units jointly owned by Virginia Power.

(2) Unit jointly owned by Dominion.

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Credit Risk

12 Months Ended

Dec. 31, 2013

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, 2013 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 any collateral. At December 31, 2013, Dominion's credit exposure totaled $263 million. Of this amount, investment grade counterparties, including those internally rated, represented 63%. No counterparty exposure exceeded 6% of Dominion's total exposure.

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, 2013, 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, 2013 and 2012, Dominion would have been required to post an additional $146 million and $110 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 $76 million in collateral at December 31, 2013 and $4 million in collateral at December 31, 2012, 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, 2013 and 2012 was $169 million and $163 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power were not material as of December 31, 2013 and 2012. See Note 7 for further information about derivative instruments.

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Derivatives and Hedge Accounting Activities (Volume of our Derivative Activity) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Current
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate	$ 2,050
Current | Natural Gas (bcf): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	116,000,000,000	[1]
Current | Natural Gas (bcf): | Basis
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	466,000,000,000	[1]
Current | Electricity (MWh): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	14,814,767	[1]
Current | Electricity (MWh): | FTRs
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	41,316,345
Current | Capacity (MW)
Derivative Instruments, Gain (Loss) [Line Items]
Capacity of Electricity (in Megawatts)	83,050
Current | Liquids (gallons)
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	151,200,000	[2]
Noncurrent
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate	750
Noncurrent | Natural Gas (bcf): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	19,000,000,000	[1]
Noncurrent | Natural Gas (bcf): | Basis
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	281,000,000,000	[1]
Noncurrent | Electricity (MWh): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	14,935,144	[1]
Noncurrent | Electricity (MWh): | FTRs
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	437,384
Noncurrent | Capacity (MW)
Derivative Instruments, Gain (Loss) [Line Items]
Capacity of Electricity (in Megawatts)	18,300
Noncurrent | Liquids (gallons)
Derivative Instruments, Gain (Loss) [Line Items]
Volume of natural gas (in billion cubic feet and gallons)	0	[2]
Virginia Electric and Power Company | Current
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate	600
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)	15,000,000,000
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)	7,000,000,000
Virginia Electric and Power Company | Current | Electricity (MWh): | Fixed Price
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	624,800
Virginia Electric and Power Company | Current | Electricity (MWh): | FTRs
Derivative Instruments, Gain (Loss) [Line Items]
Volume of electricity (in Megawatt hours)	39,186,609
Virginia Electric and Power Company | Current | Capacity (MW)
Derivative Instruments, Gain (Loss) [Line Items]
Capacity of Electricity (in Megawatts)	75,500
Virginia Electric and Power Company | Noncurrent
Derivative Instruments, Gain (Loss) [Line Items]
Interest rate	$ 0
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)	18,300

[1] Includes options.

[2] Includes NGLs and oil.

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Employee Benefit Plans (Narrative) (Details) (USD $)	3 Months Ended			12 Months Ended
	Dec. 31, 2013		Jun. 30, 2013	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Actual return on plan assets				$ 959,000,000		$ 743,000,000
Expected return on pension and other postretirement plan assets				554,000,000		509,000,000
Federal subsidy received				5,000,000
Decrease in other postretirement benefit obligations due to federal subsidy				20,000,000
Reduction in accumulated postretirement benefit obligation	220,000,000			220,000,000
Reduction in net periodic benefit cost for next year	8,000,000		36,000,000
Period for reduction in net periodic benefit cost				5 years
Accumulated benefit obligation	5,100,000,000			5,100,000,000		5,500,000,000
Cumulative required contribution period (years)				10 years
Expected contribution to voluntary employees beneficiary association				12,000,000
Percentage coverage of US stock market				7.00%
Employer contributions				40,000,000		40,000,000		38,000,000
U.S. equity:
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined benefit plan, actual plan asset allocations	28.00%			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%			18.00%
Fixed Income
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined benefit plan, actual plan asset allocations	33.00%			33.00%
Real estate:
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined benefit plan, actual plan asset allocations	3.00%			3.00%
Other alternative investments
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined benefit plan, actual plan asset allocations	18.00%			18.00%
Virginia Electric and Power Company
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Employer contributions				16,000,000		15,000,000		14,000,000
Net periodic benefit cost				96,000,000		72,000,000		50,000,000
Virginia Electric and Power Company | Dominion Retiree Health And Welfare Plan
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net periodic benefit cost				5,000,000		13,000,000		23,000,000
Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Expected reduction in net periodic benefit cost				40,000,000
Investment grade bonds average weighted maturity period				4 years
Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Expected reduction in net periodic benefit cost				60,000,000
Investment grade bonds average weighted maturity period				12 years
Pension Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Expected return on pension and other postretirement plan assets				462,000,000		430,000,000		440,000,000
Medicare Part D reimbursement			354,000,000
Reduction in accumulated postretirement benefit obligation	(22,000,000)	[1]		(22,000,000)	[1]	0	[1]	0	[1]
Discount rate			4.80%
Net periodic benefit cost				106,000,000		89,000,000		25,000,000
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Expected return on pension and other postretirement plan assets				92,000,000		79,000,000		79,000,000
Medicare Part D reimbursement			78,000,000
Reduction in accumulated postretirement benefit obligation	(7,000,000)	[1]		(7,000,000)	[1]	(2,000,000)	[1]	(1,000,000)	[1]
Discount rate	4.80%		4.70%	4.80%
Net periodic benefit cost				$ 2,000,000		$ 33,000,000		$ 63,000,000

[1] 2013 amount relates primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor.

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Employee Benefit Plans (Components of AOCI and Regulatory Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ (165)	$ (132)	$ (96)
Prior service (credit) cost	(3)	(3)	(3)
Pension Benefits | Scenario, Forecast
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	112
Prior service (credit) cost	3
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	(7)	(6)	(12)
Prior service (credit) cost	15	13	13
Other Postretirement Plans | Scenario, Forecast
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	2
Prior service (credit) cost	$ (28)

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Commitment and Contingencies (Schedule of Long Term Purchase Commitments) (Details) (Virginia Electric and Power Company, USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Long-term Purchase Commitment [Line Items]
Present value of total commitment for capacity payments	$ 1,100,000,000
Purchased electric capacity
Long-term Purchase Commitment [Line Items]
2014	336,000,000	[1]
2015	316,000,000	[1]
2016	253,000,000	[1]
2017	159,000,000	[1]
2018	104,000,000	[1]
Thereafter	163,000,000	[1]
Total	1,331,000,000	[1]
Payments	345,000,000		337,000,000	338,000,000
Energy payments
Long-term Purchase Commitment [Line Items]
Payments	$ 236,000,000		$ 214,000,000	$ 275,000,000

[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, 2013, the present value of Virginia Power's total commitment for capacity payments is $1.1 billion. Capacity payments totaled $345 million, $337 million, and $338 million, and energy payments totaled $236 million, $214 million, and $275 million for 2013, 2012 and 2011, respectively.

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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, 2013		Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 890	[1]	$ 828	[1]
Derivative liabilities	1,102	[2]	661	[2]
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	32
Derivative liabilities	48
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	4,791		4,175
Total liabilities	1,102		661
Fair Value, Measurements, Recurring | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	753		735
Derivative liabilities	1,102		595
Fair Value, Measurements, Recurring | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	137		93
Derivative liabilities			66
Fair Value, Measurements, Recurring | Equity securities: | Large Cap | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	2,417	[3]	1,973	[3]
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	13	[3]	12	[3]
Fair Value, Measurements, Recurring | Equity securities: | Other | U.S.:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	79	[3]	59	[3]
Fair Value, Measurements, Recurring | Fixed Income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	345	[3]	325	[3]
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	590	[3]	543	[3]
Fair Value, Measurements, Recurring | Fixed Income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	343	[3]	315	[3]
Fair Value, Measurements, Recurring | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3	[3]	7	[3]
Fair Value, Measurements, Recurring | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	103	[3]	80	[3]
Fair Value, Measurements, Recurring | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	8	[3]	33	[3]
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	2,927		2,460
Total liabilities	3		8
Fair Value, Measurements, Recurring | Level 1 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	3		12
Derivative liabilities	3		8
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
Derivative liabilities			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	2,417	[3]	1,973	[3]
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	13	[3]	12	[3]
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	79	[3]	59	[3]
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	[3]	0	[3]
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	415	[3]	391	[3]
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	[3]	0	[3]
Fair Value, Measurements, Recurring | Level 1 | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[3]	0	[3]
Fair Value, Measurements, Recurring | Level 1 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[3]	13	[3]
Fair Value, Measurements, Recurring | Level 1 | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[3]	0	[3]
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	1,832		1,631
Total liabilities	1,051		594
Fair Value, Measurements, Recurring | Level 2 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	718		639
Derivative liabilities	1,051		528
Fair Value, Measurements, Recurring | Level 2 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	137		93
Derivative liabilities			66
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	[3]	0	[3]
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	[3]	0	[3]
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	[3]	0	[3]
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	345	[3]	325	[3]
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	175	[3]	152	[3]
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	343	[3]	315	[3]
Fair Value, Measurements, Recurring | Level 2 | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3	[3]	7	[3]
Fair Value, Measurements, Recurring | Level 2 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	103	[3]	67	[3]
Fair Value, Measurements, Recurring | Level 2 | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	8	[3]	33	[3]
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	32		84
Total liabilities	48		59
Fair Value, Measurements, Recurring | Level 3 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	32		84
Derivative liabilities	48		59
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
Derivative liabilities			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	[3]	0	[3]
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	[3]	0	[3]
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	[3]	0	[3]
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	[3]	0	[3]
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	[3]	0	[3]
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	[3]	0	[3]
Fair Value, Measurements, Recurring | Level 3 | Fixed Income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[3]	0	[3]
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	[3]	0	[3]
Fair Value, Measurements, Recurring | Level 3 | Restricted cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	[3]	0	[3]
Virginia Electric and Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	53	[1]	6	[1]
Derivative liabilities	12	[2]	34	[2]
Virginia Electric and Power Company | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	1,716		1,409
Total liabilities	12		34
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	5		6
Derivative liabilities	12		9
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	48
Derivative liabilities			25
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	1,021	[3]	779	[3]
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	36	[3]	27	[3]
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	191	[3]	196	[3]
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	212	[3]	234	[3]
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	164	[3]	118	[3]
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	[3]
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	31	[3]	38	[3]
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	8	[3]	10	[3]
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	1,203		981
Total liabilities	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
Derivative 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]
Derivative assets	0
Derivative liabilities			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	1,021	[3]	779	[3]
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	36	[3]	27	[3]
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	[3]	0	[3]
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	146	[3]	168	[3]
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	[3]	0	[3]
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	[3]
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	0	[3]	7	[3]
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	[3]	0	[3]
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	511		423
Total liabilities	3		31
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	3		1
Derivative liabilities	3		6
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]
Derivative assets	48
Derivative liabilities			25
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	[3]	0	[3]
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	[3]	0	[3]
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	191	[3]	196	[3]
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	[3]	66	[3]
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	164	[3]	118	[3]
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	[3]
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	[3]	31	[3]
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	8	[3]	10	[3]
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	2		5
Total liabilities	9		3
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	2		5
Derivative liabilities	9		3
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]
Derivative assets	0
Derivative liabilities			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	[3]	0	[3]
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	[3]	0	[3]
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	[3]	0	[3]
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	[3]	0	[3]
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	[3]	0	[3]
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	[3]
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	[3]	0	[3]
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	[3]	$ 0	[3]

[1] At December 31, 2013, the total derivative asset balance contains $687 million of current assets, which is presented in current derivative assets, in Dominion’s Consolidated Balance Sheet, and $203 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $518 million of current assets, which is presented in current derivative assets in Dominion’s Consolidated Balance Sheet and $310 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet.

[2] At December 31, 2013, the total derivative liability balance contains $828 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet, and $274 million of noncurrent liabilities, which is presented in the other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $510 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet and $151 million of noncurrent liabilities, which is presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet.

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

XML

Investments (Recorded Other-Than-Temporary Impairment Losses on Investments) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Schedule of Available-for-sale Securities [Line Items]
Total other-than-temporary impairment losses	$ 31		$ 26		$ 75
Losses recorded to decommissioning trust regulatory liability	(13)		(10)		(24)
Losses recognized in other comprehensive income (before taxes)	10		2		3
Net impairment losses recognized in earnings	8		14		48
Other-than-temporary impairment losses for debt securities	18		4		6
Virginia Electric and Power Company
Schedule of Available-for-sale Securities [Line Items]
Total other-than-temporary impairment losses	15	[1]	11	[1]	29	[1]
Losses recorded to decommissioning trust regulatory liability	(13)		(10)		(24)
Losses recognized in other comprehensive income (before taxes)	1		0		1
Net impairment losses recognized in earnings	1		1		4
Other-than-temporary impairment losses for debt securities	$ 9		$ 2		$ 4

[1] Amounts include other-than-temporary impairment losses for debt securities of $9 million, $2 million and $4 million at December 31, 2013, 2012 and 2011, respectively.

XML

Operating Segments (Tables)

12 Months Ended

Dec. 31, 2013

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
Dominion Generation	Regulated electric fleet	X	X
	Merchant electric fleet	X
	Nonregulated retail energy marketing (electric and gas)(1)	X
Dominion Energy	Gas transmission and storage	X
	Gas distribution and storage	X
	LNG services	X
	Producer services	X

(1) As a result of Dominion's decision to realign its business units effective for 2013 year-end reporting, nonregulated retail energy marketing operations were moved from DVP to the Dominion Generation segment.

Schedule of Segment Reporting Information, by Segment

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

Year Ended December 31,	DVP(1)		Dominion Generation(1)(2)			Dominion Energy		Corporate and Other(2)			Adjustments & Eliminations(1)			Consolidated Total
(millions)
2013
Total revenue from external customers	$	1,825	$	8,445		$	1,783	$	3		$	1,064		$	13,120
Intersegment revenue	9		68			1,063		609			(1,749		)	—
Total operating revenue	1,834		8,513			2,846		612			(685		)	13,120
Depreciation, depletion and amortization	427		518			228		35			—			1,208
Equity in earnings of equity method investees	—		(14		)	21		7			—			14
Interest income	—		66			12		42			(66		)	54
Interest and related charges	175		220			26		522			(66		)	877
Income taxes	287		483			409		(287		)	—			892
Loss from discontinued operations, net of tax	—		—			—		(92		)	—			(92		)
Net income (loss) attributable to Dominion	475		1,031			643		(452		)	—			1,697
Investment in equity method investees	—		280			615		21			—			916
Capital expenditures	1,361		1,605			1,043		95			—			4,104
Total assets (billions)	11.9		22.0			12.1		8.5			(4.4		)	50.1
2012
Total revenue from external customers	$	1,846	$	8,170		$	1,813	$	155		$	851		$	12,835
Intersegment revenue	9		104			930		608			(1,651		)	—
Total operating revenue	1,855		8,274			2,743		763			(800		)	12,835
Depreciation, depletion and amortization	392		483			216		36			—			1,127
Equity in earnings of equity method investees	—		3			23		(1		)	—			25
Interest income	1		65			30		71			(106		)	61
Interest and related charges	187		177			47		511			(106		)	816
Income taxes	278		576			352		(395		)	—			811
Loss from discontinued operations, net of tax	—		—			—		(1,125		)	—			(1,125		)
Net income (loss) attributable to Dominion	439		1,021			551		(1,709		)	—			302
Investment in equity method investees	—		414			141		3			—			558
Capital expenditures	1,158		1,615			1,350		22			—			4,145
Total assets (billions)	11.5		21.8			11.2		12.6			(10.3		)	46.8
2011
Total revenue from external customers	$	1,791	$	8,759		$	2,044	$	56		$	1,115		$	13,765
Intersegment revenue	63		123			1,077		595			(1,858		)	—
Total operating revenue	1,854		8,882			3,121		651			(743		)	13,765
Depreciation, depletion and amortization	369		413			207		29			—			1,018
Equity in earnings of equity method investees	—		3			23		9			—			35
Interest income	10		65			27		71			(106		)	67
Interest and related charges	183		148			57		514			(106		)	796
Income taxes	264		655			323		(464		)	—			778
Loss from discontinued operations, net of tax	—		—			—		(58		)	—			(58		)
Net income (loss) attributable to Dominion	416		1,078			521		(607		)	—			1,408
Capital expenditures	1,091		1,593			907		61			—			3,652

(1) Amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

(2) Segment information for 2012 and 2011 has been recast to reflect Brayton Point and Kincaid 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)
2013
Operating revenue	$	1,826	$	5,475	$	(6	)	$	—		$	7,295
Depreciation and amortization	427		425		1			—			853
Interest income	—		6		—			—			6
Interest and related charges	175		192		2			—			369
Income taxes	286		399		(26		)	—			659
Net income (loss)	483		702		(47		)	—			1,138
Capital expenditures	1,360		1,173		—			—			2,533
Total assets (billions)	12.0		15.1		—			(0.1		)	27.0
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

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Long-Term Debt Long Term Debt (Schedule of Equity Units) (Details) (USD $) Share data in Millions, unless otherwise specified	12 Months Ended		0 Months Ended				0 Months Ended
	Dec. 31, 2013		Jun. 07, 2013 Capital Unit, Class A		Sep. 30, 2013 Capital Unit, Class A Remarketable Subordinated Notes	Jun. 07, 2013 Capital Unit, Class A Remarketable Subordinated Notes	Jun. 07, 2013 Capital Unit, Class B		Sep. 30, 2013 Capital Unit, Class B Remarketable Subordinated Notes	Jun. 07, 2013 Capital Unit, Class B Remarketable Subordinated Notes
Capital Unit [Line Items]
Units Issued			0				0
Total Net Proceeds			$ 533,500,000				$ 553,500,000
Total Long-term Debt						550,000,000				550,000,000
RSN Annual Interest Rate					1.07%				1.18%
Stock Purchase Contract Annual Rate			5.055%				4.82%
Stock Purchase Contract Liability	139,000,000	[1]	76,700,000	[1]			79,300,000	[1]
Total payments	$ 17,000,000

[1] Payments of $17 million were made in 2013. The stock purchase contract liability was $139 million at December 31, 2013.

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Commitments and Contingencies (Lease Commitments) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Loss Contingencies [Line Items]
2014	$ 63
2015	60
2016	51
2017	43
2018	37
Thereafter	87
Total	341
Virginia Electric and Power Company
Loss Contingencies [Line Items]
2014	27
2015	26
2016	21
2017	17
2018	14
Thereafter	27
Total	$ 132

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Fair Value Measurements (Financial Instruments' Carrying Amounts and Fair Values) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including securities due within one year	$ 20,842
Subsidiary preferred stock	257		257
Valuation of certain fair value hedges	55		93
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	18,396	[1]	16,841	[1]
Long-term debt - VIEs	0	[2]	860	[2]
Junior subordinated notes	1,373	[2]	1,373	[2]
Remarketable subordinated notes	1,080	[2]	0	[2]
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	19,887	[1],[4]	19,898	[1],[4]
Long-term debt - VIEs	0	[2],[4]	864	[2],[4]
Junior subordinated notes	1,394	[2],[4]	1,430	[2],[4]
Remarketable subordinated notes	1,192	[2],[4]	0	[2],[4]
Subsidiary preferred stock	261	[3],[4]	255	[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	8,043
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	8,032	[1]	6,669	[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	8,897	[1],[4]	8,270	[1],[4]
Subsidiary preferred stock	$ 261	[3],[4]	$ 255	[3],[4]

[1] Carrying amount includes amounts which represent the unamortized discount and premium. At December 31, 2013, and 2012, includes the valuation of certain fair value hedges associated with Dominion's fixed rate debt, of approximately $55 million and $93 million, respectively.

[2] Carrying amount includes amounts which represent the unamortized discount or premium.

[3] Includes deferred issuance expenses of $2 million at December 31, 2013 and 2012.

[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.

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Investments (Marketable Equity and Debt Securities and Cash Equivalents (Classified as Available-for-sale) and Cost Method Investments in Decommissioning Trust Funds) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Investment Holdings [Line Items]
Total amortized cost basis	$ 2,669		$ 2,511
Total Unrealized Gains	1,252	[1]	821	[1]
Total Unrealized Losses	(18)	[1],[2]	(2)	[1],[2]
Fair Value	3,903		3,330
Net assets related to pending sales and purchases of securities	11		6
Fair value of securities in an unrealized loss position	604		195
Virginia Electric and Power Company
Investment Holdings [Line Items]
Total amortized cost basis	1,236		1,179
Total Unrealized Gains	538	[1]	337	[1]
Total Unrealized Losses	(9)	[1],[3]	(1)	[1],[3]
Fair Value	1,765		1,515
Net assets related to pending sales and purchases of securities	6		6
Fair value of securities in an unrealized loss position	299		104
Cost method investments
Investment Holdings [Line Items]
Other investments and securities, at cost	106		117
Total Unrealized Gains	0	[1]	0	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	106		117
Cost method investments | Virginia Electric and Power Company
Investment Holdings [Line Items]
Other investments and securities, at cost	106		117
Total Unrealized Gains	0	[1]	0	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	106		117
Cash equivalents and other
Investment Holdings [Line Items]
Other investments and securities, at cost	110	[4]	72	[4]
Total Unrealized Gains	0	[1],[4]	0	[1],[4]
Total Unrealized Losses	0	[1],[4]	0	[1],[4]
Fair Value	110	[4]	72	[4]
Cash equivalents and other | Virginia Electric and Power Company
Investment Holdings [Line Items]
Other investments and securities, at cost	37	[5]	44	[5]
Total Unrealized Gains	0	[1],[5]	0	[1],[5]
Total Unrealized Losses	0	[1],[5]	0	[1],[5]
Fair Value	37	[5]	44	[5]
Corporate debt instruments
Investment Holdings [Line Items]
Amortized Cost	332		295
Total Unrealized Gains	16	[1]	30	[1]
Total Unrealized Losses	(3)	[1]	0	[1]
Fair Value	345		325
Corporate debt instruments | Virginia Electric and Power Company
Investment Holdings [Line Items]
Amortized Cost	185		179
Total Unrealized Gains	8	[1]	17	[1]
Total Unrealized Losses	(2)	[1]	0	[1]
Fair Value	191		196
U.S. Treasury securities and agency debentures
Investment Holdings [Line Items]
Amortized Cost	589		523
Total Unrealized Gains	8	[1]	19	[1]
Total Unrealized Losses	(10)	[1]	(2)	[1]
Fair Value	587		540
U.S. Treasury securities and agency debentures | Virginia Electric and Power Company
Investment Holdings [Line Items]
Amortized Cost	214		231
Total Unrealized Gains	1	[1]	4	[1]
Total Unrealized Losses	(3)	[1]	(1)	[1]
Fair Value	212		234
State and municipal
Investment Holdings [Line Items]
Amortized Cost	297		248
Total Unrealized Gains	11	[1]	26	[1]
Total Unrealized Losses	(5)	[1]	0	[1]
Fair Value	303		274
State and municipal | Virginia Electric and Power Company
Investment Holdings [Line Items]
Amortized Cost	163		106
Total Unrealized Gains	4	[1]	11	[1]
Total Unrealized Losses	(4)	[1]	0	[1]
Fair Value	163		117
Other
Investment Holdings [Line Items]
Amortized Cost	3		6
Total Unrealized Gains	0	[1]	1	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	3		7
Other | Virginia Electric and Power Company
Investment Holdings [Line Items]
Amortized Cost			1
Total Unrealized Gains			0	[1]
Total Unrealized Losses			0	[1]
Fair Value			1
U.S.: | Equity securities: | Large Cap
Investment Holdings [Line Items]
Amortized Cost	1,183		1,210
Total Unrealized Gains	1,194	[1]	732	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	2,377		1,942
U.S.: | Equity securities: | Large Cap | Virginia Electric and Power Company
Investment Holdings [Line Items]
Amortized Cost	506		481
Total Unrealized Gains	514	[1]	298	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	1,020		779
U.S.: | Equity securities: | Other
Investment Holdings [Line Items]
Amortized Cost	49		40
Total Unrealized Gains	23	[1]	13	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	72		53
U.S.: | Equity securities: | Other | Virginia Electric and Power Company
Investment Holdings [Line Items]
Amortized Cost	25		20
Total Unrealized Gains	11	[1]	7	[1]
Total Unrealized Losses	0	[1]	0	[1]
Fair Value	$ 36		$ 27

[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 $604 million and $195 million at December 31, 2013 and 2012, respectively.

[3] The fair value of securities in an unrealized loss position was $299 million and $104 million at December 31, 2013 and 2012, respectively.

[4] Includes pending sales of securities of $11 million and pending purchases of securities of $6 million at December 31, 2013 and 2012, respectively.

[5] Includes pending sales of securities of $6 million at December 31, 2013 and 2012.

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Derivatives and Hedge Accounting Activities (Fair Values of our Derivatives) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	$ 890		$ 828
Total Fair Value, Liabilities	1,102		661
Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	687		518
Current Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	571		482
Current Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	116		36
Noncurrent Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	203	[1]	310	[1]
Noncurrent Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	182		253
Noncurrent Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	21		57
Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	828		510
Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	828		444
Current Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			66
Noncurrent Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	274	[2]	151	[2]
Noncurrent Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	274		151
Fair Value - Derivatives under Hedge Accounting
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	214		326
Total Fair Value, Liabilities	386		227
Fair Value - Derivatives under Hedge Accounting | Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	165		139
Fair Value - Derivatives under Hedge Accounting | Current Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	49		103
Fair Value - Derivatives under Hedge Accounting | Current Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	116		36
Fair Value - Derivatives under Hedge Accounting | Noncurrent Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	49	[1]	187	[1]
Fair Value - Derivatives under Hedge Accounting | Noncurrent Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	28		130
Fair Value - Derivatives under Hedge Accounting | Noncurrent Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	21		57
Fair Value - Derivatives under Hedge Accounting | Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	267		169
Fair Value - Derivatives under Hedge Accounting | Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	267		103
Fair Value - Derivatives under Hedge Accounting | Current Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			66
Fair Value - Derivatives under Hedge Accounting | Noncurrent Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	119	[2]	58	[2]
Fair Value - Derivatives under Hedge Accounting | Noncurrent Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	119		58
Fair Value - Derivatives not under Hedge Accounting
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	676		502
Total Fair Value, Liabilities	716		434
Fair Value - Derivatives not under Hedge Accounting | Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	522		379
Fair Value - Derivatives not under Hedge Accounting | Current Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	522		379
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	154	[1]	123	[1]
Fair Value - Derivatives not under Hedge Accounting | Noncurrent Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	154		123
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	561		341
Fair Value - Derivatives not under Hedge Accounting | Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	561		341
Fair Value - Derivatives not under Hedge Accounting | Current Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			0
Fair Value - Derivatives not under Hedge Accounting | Noncurrent Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	155	[2]	93	[2]
Fair Value - Derivatives not under Hedge Accounting | Noncurrent Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	155		93
Virginia Electric and Power Company
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	53		6
Total Fair Value, Liabilities	12		34
Virginia Electric and Power Company | Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	53	[3]	6	[3]
Virginia Electric and Power Company | Current Assets | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	5		6
Virginia Electric and Power Company | Current Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	48
Virginia Electric and Power Company | Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	12		33
Virginia Electric and Power Company | Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	12		8
Virginia Electric and Power Company | Current Liabilities | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			25
Virginia Electric and Power Company | Noncurrent Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			1	[4]
Virginia Electric and Power Company | Noncurrent Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities			1
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	50		1
Total Fair Value, Liabilities	1		31
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	50	[3]	1	[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	2		1
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Current Assets | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	48
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	1		30
Virginia Electric and Power Company | Fair Value - Derivatives under Hedge Accounting | Current Liabilities | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	1		5
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
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]
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
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	3		5
Total Fair Value, Liabilities	11		3
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting | Current Assets
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Assets	3	[3]	5	[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	3		5
Virginia Electric and Power Company | Fair Value - Derivatives not under Hedge Accounting | Current Liabilities
Derivative Instruments, Gain (Loss) [Line Items]
Total Fair Value, Liabilities	11		3
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	11		3
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
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]
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

[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.

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Investments (Fair Value of our Marketable Debt Securities by Contractual Maturity) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Schedule of Available-for-sale Securities [Line Items]
Due in one year or less	$ 128
Due after one year through five years	357
Due after five years through ten years	362
Due after ten years	391
Total	1,238
Virginia Electric and Power Company
Schedule of Available-for-sale Securities [Line Items]
Due in one year or less	31
Due after one year through five years	163
Due after five years through ten years	196
Due after ten years	176
Total	$ 566

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Derivatives and Hedge Accounting Activities (Schedule of Offsetting Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 883		$ 799
Total derivatives, not subject to a master netting or similar arrangement	7		29
Derivative Asset	890	[1]	828	[1]
Gross Amounts Offset in the Consolidated Balance Sheet	0	[1]	0	[1]
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	568		466
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0		4
Net Amounts	315		329
Derivative assets, current	687		518
Derivative assets, noncurrent	620		212
Current Assets
Offsetting Assets [Line Items]
Derivative assets, current	687
Non Current Derivative Assets
Offsetting Assets [Line Items]
Derivative assets, noncurrent	203		310
Current Derivative Assets
Offsetting Assets [Line Items]
Derivative assets, current			518
Interest rate | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	137		93
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	0		19
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0		0
Net Amounts	137		74
Commodity | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	240		290
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	63		97
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0		0
Net Amounts	177		193
Commodity | Exchange
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	506		416
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	505		350
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0		4
Net Amounts	1		62
Virginia Electric and Power Company
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	53		6
Total derivatives, not subject to a master netting or similar arrangement	0		0
Derivative Asset	53	[1]	6	[1]
Gross Amounts Offset in the Consolidated Balance Sheet	0	[1]	0	[1]
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	4		3
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0		0
Net Amounts	49		3
Derivative assets, noncurrent	11		18
Virginia Electric and Power Company | Current Assets
Offsetting Assets [Line Items]
Derivative assets, current	53		6
Virginia Electric and Power Company | Interest rate | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	48		0
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0		0
Net Amounts	48		0
Virginia Electric and Power Company | Commodity | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	4		6
Gross Amounts Offset in the Consolidated Balance Sheet	0		0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	4		3
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0		0
Net Amounts	0		3
Virginia Electric and Power Company | Commodity | Exchange
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	1
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0
Net Amounts	$ 1

[1] At December 31, 2013, the total derivative asset balance contains $687 million of current assets, which is presented in current derivative assets, in Dominion’s Consolidated Balance Sheet, and $203 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $518 million of current assets, which is presented in current derivative assets in Dominion’s Consolidated Balance Sheet and $310 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet.

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Fair Value Measurements (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended		3 Months Ended		1 Months Ended		3 Months Ended					12 Months Ended		1 Months Ended
	Dec. 31, 2013	Dec. 31, 2013 Kewaunee Utility	Jun. 30, 2012 Salem Harbor	Dec. 31, 2013 Elwood	Sep. 30, 2012 Fair Value, Measurements, Nonrecurring Kewaunee	Mar. 31, 2011 Fair Value, Measurements, Nonrecurring State Line Operating Expense	Sep. 30, 2011 Fair Value, Measurements, Nonrecurring Emissions allowances	Sep. 30, 2011 Fair Value, Measurements, Nonrecurring Emissions allowances Operating Expense	Sep. 30, 2011 Fair Value, Measurements, Nonrecurring Emissions allowances Loss from Discontinued Operations	Sep. 30, 2011 Fair Value, Measurements, Nonrecurring Emissions allowances Virginia Electric and Power Company Operating Expense	Mar. 31, 2011 Fair Value, Measurements, Nonrecurring Maximum State Line	Dec. 31, 2012 Fair Value, Measurements, Nonrecurring Brayton Point	Dec. 31, 2012 Fair Value, Measurements, Nonrecurring Brayton Point Level 2	Jun. 30, 2013 Gas, Transmission and Distribution Equipment	Dec. 31, 2013 Gas, Transmission and Distribution Equipment Fair Value, Measurements, Nonrecurring Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment charge														$ 49
Impairment charge after tax														29
Estimated fair value											1				1
Ownership percentage				50.00%
Impairment charge	1,600				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					24
Severance costs net of tax					16
Impairment charge						55
Impairment charge, net of tax						39
After tax charge on disposal of assets			27
Pretax charge on disposal of assets			16
So2 emissions allowances obtained for arp cnd cair compliance								57		43
Salem Harbor, impairment charge							14	57	43	43
Impairment of intangible assets after tax							$ 8	$ 34	$ 26	$ 26

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Variable Interest Entities

12 Months Ended

Dec. 31, 2013

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 $864 million as of December 31, 2013. Virginia Power paid $217 million, $214 million, and $211 million for electric capacity and $98 million, $83 million, and $125 million for electric energy to these entities for the years ended December 31, 2013, 2012 and 2011, respectively.

Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $331 million, $328 million, and $389 million for the years ended December 31, 2013, 2012 and 2011, respectively. Virginia Power determined that it is not the most closely associated entity with DRS and therefore not the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power. Virginia Power has no obligation to absorb more than its allocated share of DRS costs.

Through August 2013, Dominion leased the Fairless generating facility in Pennsylvania from Juniper, the lessor, which began commercial operations in June 2004. Dominion made annual lease payments of approximately $53 million.

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

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

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

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

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Operating Segment (Schedule of Segment Reporting Information, by Segment) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended										12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012		Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting Information [Line Items]
Operating Revenue	$ 3,185	[1]	$ 3,432	$ 2,980	$ 3,523	$ 3,101		$ 3,332	$ 3,005	$ 3,397	$ 13,120		$ 12,835	[2]	$ 13,765	[2]
Total operating revenue											13,120		12,835		13,765
Depreciation, depletion and amortization											1,208		1,127		1,018
Equity in earnings of equity method investees											14		25		35
Interest income											54		61		67
Interest and related charges											877		816		796
Income tax expense											892	[3]	811	[2],[3]	778	[2],[3]
Loss from discontinued operations, net of tax											(92)		(1,125)	[2],[4]	(58)	[2],[4]
Net income (loss) attributable to Dominion	431	[1]	569	202	495	(659)		209	258	494	1,697		302	[2]	1,408	[2]
Investment in equity method affiliates	916					558					916		558
Capital expenditures											4,104		4,145		3,652
Total assets	50,096					46,838					50,096		46,838
Intersegment revenue
Segment Reporting Information [Line Items]
Operating Revenue											0		0		0
DVP
Segment Reporting Information [Line Items]
Operating Revenue											1,825	[5]	1,846	[5]	1,791	[5]
Total operating revenue											1,834	[5]	1,855	[5]	1,854	[5]
Depreciation, depletion and amortization											427	[5]	392	[5]	369	[5]
Equity in earnings of equity method investees											0	[5]	0	[5]	0	[5]
Interest income											0	[5]	1	[5]	10	[5]
Interest and related charges											175	[5]	187	[5]	183	[5]
Income tax expense											287	[5]	278	[5]	264	[5]
Loss from discontinued operations, net of tax											0	[5]	0	[5]	0	[5]
Net income (loss) attributable to Dominion											475	[5]	439	[5]	416	[5]
Investment in equity method affiliates	0	[5]				0	[5]				0	[5]	0	[5]
Capital expenditures											1,361	[5]	1,158	[5]	1,091	[5]
Total assets	11,900	[5]				11,500	[5]				11,900	[5]	11,500	[5]
DVP | Intersegment revenue
Segment Reporting Information [Line Items]
Operating Revenue											9	[5]	9	[5]	63	[5]
Dominion Generation
Segment Reporting Information [Line Items]
Operating Revenue											8,445	[5],[6]	8,170	[5],[6]	8,759	[5],[6]
Total operating revenue											8,513	[5],[6]	8,274	[5],[6]	8,882	[5],[6]
Depreciation, depletion and amortization											518	[5],[6]	483	[5],[6]	413	[5],[6]
Equity in earnings of equity method investees											(14)	[5],[6]	3	[5],[6]	3	[5],[6]
Interest income											66	[5],[6]	65	[5],[6]	65	[5],[6]
Interest and related charges											220	[5],[6]	177	[5],[6]	148	[5],[6]
Income tax expense											483	[5],[6]	576	[5],[6]	655	[5],[6]
Loss from discontinued operations, net of tax											0	[5],[6]	0	[5],[6]	0	[5],[6]
Net income (loss) attributable to Dominion											1,031	[5],[6]	1,021	[5],[6]	1,078	[5],[6]
Investment in equity method affiliates	280	[5],[6]				414	[5],[6]				280	[5],[6]	414	[5],[6]
Capital expenditures											1,605	[5],[6]	1,615	[5],[6]	1,593	[5],[6]
Total assets	22,000	[5],[6]				21,800	[5],[6]				22,000	[5],[6]	21,800	[5],[6]
Dominion Generation | Intersegment revenue
Segment Reporting Information [Line Items]
Operating Revenue											68	[5],[6]	104	[5],[6]	123	[5],[6]
Dominion Energy
Segment Reporting Information [Line Items]
Operating Revenue											1,783		1,813		2,044
Total operating revenue											2,846		2,743		3,121
Depreciation, depletion and amortization											228		216		207
Equity in earnings of equity method investees											21		23		23
Interest income											12		30		27
Interest and related charges											26		47		57
Income tax expense											409		352		323
Loss from discontinued operations, net of tax											0		0		0
Net income (loss) attributable to Dominion											643		551		521
Investment in equity method affiliates	615					141					615		141
Capital expenditures											1,043		1,350		907
Total assets	12,100					11,200					12,100		11,200
Dominion Energy | Intersegment revenue
Segment Reporting Information [Line Items]
Operating Revenue											1,063		930		1,077
Corporate and Other
Segment Reporting Information [Line Items]
Operating Revenue											3	[6]	155	[6]	56	[6]
Total operating revenue											612	[6]	763	[6]	651	[6]
Depreciation, depletion and amortization											35	[6]	36	[6]	29	[6]
Equity in earnings of equity method investees											7	[6]	(1)	[6]	9	[6]
Interest income											42	[6]	71	[6]	71	[6]
Interest and related charges											522	[6]	511	[6]	514	[6]
Income tax expense											(287)	[6]	(395)	[6]	(464)	[6]
Loss from discontinued operations, net of tax											(92)	[6]	(1,125)	[6]	(58)	[6]
Net income (loss) attributable to Dominion											(452)	[6]	(1,709)	[6]	(607)	[6]
Investment in equity method affiliates	21	[6]				3	[6]				21	[6]	3	[6]
Capital expenditures											95	[6]	22	[6]	61	[6]
Total assets	8,500	[6]				12,600	[6]				8,500	[6]	12,600	[6]
Corporate and Other | Intersegment revenue
Segment Reporting Information [Line Items]
Operating Revenue											609	[6]	608	[6]	595	[6]
Adjustments & Eliminations
Segment Reporting Information [Line Items]
Operating Revenue											1,064	[5]	851	[5]	1,115	[5]
Total operating revenue											(685)	[5]	(800)	[5]	(743)	[5]
Depreciation, depletion and amortization											0	[5]	0	[5]	0	[5]
Equity in earnings of equity method investees											0	[5]	0	[5]	0	[5]
Interest income											(66)	[5]	(106)	[5]	(106)	[5]
Interest and related charges											(66)	[5]	(106)	[5]	(106)	[5]
Income tax expense											0	[5]	0	[5]	0	[5]
Loss from discontinued operations, net of tax											0	[5]	0	[5]	0	[5]
Net income (loss) attributable to Dominion											0	[5]	0	[5]	0	[5]
Investment in equity method affiliates	0	[5]				0	[5]				0	[5]	0	[5]
Capital expenditures											0	[5]	0	[5]	0	[5]
Total assets	(4,400)	[5]				(10,300)	[5]				(4,400)	[5]	(10,300)	[5]
Adjustments & Eliminations | Intersegment revenue
Segment Reporting Information [Line Items]
Operating Revenue											(1,749)	[5]	(1,651)	[5]	(1,858)	[5]
Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Operating Revenue	1,745		2,059	1,710	1,781	1,630		2,086	1,756	1,754	7,295		7,226		7,246
Total operating revenue											7,295		7,226		7,246
Depreciation, depletion and amortization											853		782		718
Interest income											6		8		18
Interest and related charges											369		385		331
Income tax expense											659	[7]	653	[7]	540	[7]
Net income (loss) attributable to Dominion	199		387	265	287	220		415	172	243	1,138		1,050		822
Capital expenditures											2,533		2,288		2,090
Total assets	26,961					24,811					26,961		24,811
Virginia Electric and Power Company | DVP
Segment Reporting Information [Line Items]
Total operating revenue											1,826		1,847		1,793
Depreciation, depletion and amortization											427		392		368
Interest income											0		1		10
Interest and related charges											175		186		182
Income tax expense											286		277		265
Net income (loss) attributable to Dominion											483		448		426
Capital expenditures											1,360		1,142		1,081
Total assets	12,000					11,400					12,000		11,400
Virginia Electric and Power Company | Dominion Generation
Segment Reporting Information [Line Items]
Total operating revenue											5,475		5,379		5,546
Depreciation, depletion and amortization											425		390		350
Interest income											6		7		8
Interest and related charges											192		199		199
Income tax expense											399		403		447
Net income (loss) attributable to Dominion											702		653		664
Capital expenditures											1,173		1,146		1,009
Total assets	15,100					14,800					15,100		14,800
Virginia Electric and Power Company | Corporate and Other
Segment Reporting Information [Line Items]
Total operating revenue											(6)		0		(93)
Depreciation, depletion and amortization											1		0		0
Interest income											0		0		0
Interest and related charges											2		0		(50)
Income tax expense											(26)		(27)		(172)
Net income (loss) attributable to Dominion											(47)		(51)		(268)
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 tax expense											0		0		0
Net income (loss) attributable to Dominion											0		0		0
Capital expenditures											0		0		0
Total assets	$ (100)					$ (1,400)					$ (100)		$ (1,400)

[1] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3.

[2] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

[3] In 2012, Dominion’s current federal income tax expense for continuing and discontinued operations includes a $195 million benefit related to a carryback of its 2012 net operating loss. In 2011, Dominion’s deferred federal income tax expense includes the recognition of a $346 million benefit, including $51 million related to discontinued operations, for its 2011 net operating loss expected to be used to reduce taxable income in future years.

[4] Includes income tax benefit of $43 million, $692 million, and $33 million in 2013, 2012 and 2011, respectively. For 2012, includes impairment charges of $1.6 billion related to Brayton Point and Kincaid. See Note 6 for additional information.

[5] Amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

[6] Segment information for 2012 and 2011 has been recast to reflect Brayton Point and Kincaid as discontinued operations, as discussed in Note 3.

[7] In 2011, Virginia Power’s deferred federal income tax expense includes a $54 million benefit related to a portion of its 2011 net operating loss that is expected to be used in future years. Also, Virginia Power’s current federal income tax expense reflects the amounts of its 2011 net operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

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Short-Term Debt And Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2013

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:

	Facility Limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Capacity Available
(millions)
At December 31, 2013
Joint revolving credit facility(1)	$	3,000	$	1,927		$	—	$	1,073
Joint revolving credit facility(2)	500		—			11		489
Total	$	3,500	$	1,927	(3)	$	11	$	1,562
At December 31, 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

(1) Effective September 2013, the maturity date was extended from September 2017 to September 2018. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.

(2) Effective September 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion's credit facilities were 0.33% and 0.49% at December 31, 2013 and 2012, 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:

	Facility Sub-limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Sub-limit Capacity Available
(millions)
At December 31, 2013
Joint revolving credit facility(1)	$	1,000	$	842		$	—	$	158
Joint revolving credit facility(2)	250		—			1		249
Total	$	1,250	$	842	(3)	$	1	$	407
At December 31, 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

(1) Effective September 2013, the maturity date was extended from September 2017 to September 2018. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power's current sub-limit under this credit facility can be increased or decreased multiple times per year.

(2) Effective September 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power's 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 0.33% and 0.47% at December 31, 2013 and 2012, respectively.

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value, Option, Quantitative Disclosures

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

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range		Weighted Average(1)
At December 31, 2013
Assets:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	14	Discounted Cash Flow	Market Price (per Dth)	(5)	(2) - 5		2
FTRs (3)	2		Discounted Cash Flow	Market Price (per MWh)	(5)	(1) - 5		—
Liquids(4)	6		Discounted Cash Flow	Market Price (per Gal)	(5)	1 - 3		1
Physical and Financial Options:
Natural Gas(2)	4		Option Model	Market Price (per Dth)	(5)	3 - 5		4
				Price Volatility	(6)	14% - 36%		20	%
				Price Correlation	(7)	(9%) - 100%		36	%
				Mean Reversion	(8)	.01 - 1		.53
Full Requirements Contracts:
Electricity	6		Discounted Cash Flow	Market Price (per MWh)	(5)	10 - 406	(11)	42
				Load Shaping	(9)	0% - 10%		7	%
				Usage Factor	(10)	11% - 29%		16	%
Total assets	$	32
Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	19	Discounted Cash Flow	Market Price (per Dth)	(5)	(2) - 30		1
Electricity	1		Discounted Cash Flow	Market Price (per MWh)	(5)	28 - 240	(11)	39
FTRs(3)	9		Discounted Cash Flow	Market Price (per MWh)	(5)	(1) - 5		1
Liquids(4)	11		Discounted Cash Flow	Market Price (per Gal)	(5)	1 - 3		1
Physical and Financial Options:
Natural Gas(2)	8		Option Model	Market Price (per Dth)	(5)	3 - 11		7
				Price Volatility	(6)	14% - 36%		20	%
				Price Correlation	(7)	(9%) - 100%		36	%
				Mean Reversion	(8)	.01-1		.53
Total liabilities	$	48

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Includes NGLs.

(5) Represents market prices beyond defined terms for Levels 1 and 2.

(6) Represents volatilities unrepresented in published markets.

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

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

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

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

(11) 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 Shaping	Sell(1)	Increase (decrease)	Loss (gain)
Usage Factor	Sell(2)	Increase (decrease)	Gain (loss)
Mean Reversion	Buy	Increase (decrease)	Loss (gain)
Mean Reversion	Sell	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, 2013
Assets:
Derivatives:
Commodity	$	3	$	718	$	32	$	753
Interest rate	—		137		—		137
Investments(1):
Equity securities:
U.S.:
Large Cap	2,417		—		—		2,417
Other	79		—		—		79
Non-U.S.:
Large Cap	13		—		—		13
Fixed Income:
Corporate debt instruments	—		345		—		345
U.S. Treasury securities and agency debentures	415		175		—		590
State and municipal	—		343		—		343
Other	—		3		—		3
Cash equivalents and other	—		103		—		103
Restricted cash equivalents	—		8		—		8
Total assets	$	2,927	$	1,832	$	32	$	4,791
Liabilities:
Derivatives:
Commodity	$	3	$	1,051	$	48	$	1,102
Total liabilities	$	3	$	1,051	$	48	$	1,102
At December 31, 2012
Assets:
Derivatives:
Commodity	$	12	$	639	$	84	$	735
Interest rate	—		93		—		93
Investments(1):
Equity securities:
U.S.:
Large Cap	1,973		—		—		1,973
Other	59		—		—		59
Non-U.S.:
Large Cap	12		—		—		12
Fixed Income:
Corporate debt instruments	—		325		—		325
U.S. Treasury securities and agency debentures	391		152		—		543
State and municipal	—		315		—		315
Other	—		7		—		7
Cash equivalents and other	13		67		—		80
Restricted cash equivalents	—		33		—		33
Total assets	$	2,460	$	1,631	$	84	$	4,175
Liabilities:
Derivatives:
Commodity	$	8	$	528	$	59	$	595
Interest rate	—		66		—		66
Total liabilities	$	8	$	594	$	59	$	661

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

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:

	2013			2012			2011
(millions)
Balance at January 1,	$	25		$	(71	)	$	(50	)
Total realized and unrealized gains (losses):
Included in earnings	(9		)	(15		)	(77		)
Included in other comprehensive income (loss)	1			101			14
Included in regulatory assets/liabilities	(9		)	30			(42		)
Settlements	(23		)	47			88
Transfers out of Level 3	(1		)	(67		)	(4		)
Balance at December 31,	$	(16	)	$	25		$	(71	)
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

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, 2013
Total gains (losses) included in earnings	$	11		$	(19	)	$	(1	)	$	(9	)
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	1			—			(1		)	—
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

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,	2013				2012
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	18,396	$	19,887	$	16,841	$	19,898
Long-term debt, including securities due within one year - VIE(3)	—		—		860		864
Junior subordinated notes(3)	1,373		1,394		1,373		1,430
Remarketable subordinated notes(3)	1,080		1,192		—		—
Subsidiary preferred stock(4)	257		261		257		255
Virginia Power
Long-term debt, including securities due within one year(2)	$	8,032	$	8,897	$	6,669	$	8,270
Preferred stock(4)	257		261		257		255

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2) Carrying amount includes amounts which represent the unamortized discount and premium. At December 31, 2013, and 2012, includes the valuation of certain fair value hedges associated with Dominion's fixed rate debt, of approximately $55 million and $93 million, respectively.

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

(4) Includes deferred issuance expenses of $2 million at December 31, 2013 and 2012.

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, 2013
Assets:
Derivatives:
Commodity	$	—	$	3	$	2	$	5
Interest rate	—		48		—		48
Investments(1):
Equity securities:
U.S.:
Large Cap	1,021		—		—		1,021
Other	36		—		—		36
Fixed Income:
Corporate debt instruments	—		191		—		191
U.S. Treasury securities and agency debentures	146		66		—		212
State and municipal	—		164		—		164
Cash equivalents and other	—		31		—		31
Restricted cash equivalents	—		8		—		8
Total assets	$	1,203	$	511	$	2	$	1,716
Liabilities:
Derivatives:
Commodity	$	—	$	3	$	9	$	12
Total Liabilities	$	—	$	3	$	9	$	12
At December 31, 2012
Assets:
Derivatives:
Commodity	$	—	$	1	$	5	$	6
Investments(1):
Equity securities:
U.S.:
Large Cap	779		—		—		779
Other	27		—		—		27
Fixed Income:
Corporate debt instruments	—		196		—		196
U.S. Treasury securities and agency debentures	168		66		—		234
State and municipal	—		118		—		118
Other	—		1		—		1
Cash equivalents and other	7		31		—		38
Restricted cash equivalents	—		10		—		10
Total assets	$	981	$	423	$	5	$	1,409
Liabilities:
Derivatives:
Commodity	$	—	$	6	$	3	$	9
Interest rate	—		25		—		25
Total Liabilities	$	—	$	31	$	3	$	34

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

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:

	2013			2012			2011
(millions)
Balance at January 1,	$	2		$	(28	)	$	14
Total realized and unrealized gains (losses):
Included in earnings	(17		)	(50		)	(45		)
Included in regulatory assets/liabilities	(9		)	30			(42		)
Settlements	17			50			45
Balance at December 31,	$	(7	)	$	2		$	(28	)

XML

Fair Value Measurements (Schedule of Gains and Losses Included in the Level 3 Fair Value Category) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) included in earnings	$ (9)	$ (15)	$ (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	0	42	22
Operating Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) included in earnings	11	35	(32)
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	1	42	22
Electric Fuel and Energy Purchases
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) included in earnings	(19)	(50)	(45)
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	(1)	0	0
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	$ (1)	$ 0	$ 0

XML

Goodwill and Intangible Assets (Annual Amortization Expense of Intangible Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
2014	$ 69
2015	59
2016	50
2017	40
2018	29
Virginia Electric and Power Company
Finite-Lived Intangible Assets [Line Items]
2014	21
2015	15
2016	12
2017	9
2018	$ 5

XML

Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2013

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, 2013 and 2012 included $555 million and $411 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, 2013 and 2012 included $395 million and $348 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;

• 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 84% 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. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, 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.

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 2013, Dominion recognized interest income of $3 million and interest expense of $10 million and no penalties. In 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. Dominion had accrued interest receivable of $5 million, interest payable of $15 million and penalties payable of less than $1 million at December 31, 2013 and interest receivable of $5 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2012.

Virginia Power's interest and penalties were immaterial in 2013 and 2012. In 2011, Virginia Power recognized interest income of $12 million, and penalties were immaterial.

At December 31, 2013, Virginia Power's Consolidated Balance Sheet included $3 million of state income taxes receivable, $22 million of federal and state income taxes payable, $12 million of noncurrent state income taxes receivable and $28 million of noncurrent federal and state income taxes payable.

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.

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, 2013 and 2012, Dominion's accounts payable included $38 million and $53 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 2013 and 2012, Virginia Power's accounts payable included $21 million and $30 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 $620 million and $212 million associated with cash collateral at December 31, 2013 and 2012, respectively. Dominion had margin liabilities of $2 million and $4 million associated with cash collateral at December 31, 2013 and 2012, respectively. Virginia Power had margin assets of $11 million and $18 million associated with cash collateral at December 31, 2013 and 2012, respectively. Virginia Power's margin liabilities associated with cash collateral were not material at December 31, 2013 and 2012. See Note 7 for further information about offsetting derivatives.

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 is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, 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 generally charged to expense as it is incurred.

In 2013, 2012 and 2011, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $66 million, $91 million and $85 million, respectively. In 2013, 2012 and 2011, Virginia Power capitalized AFUDC to property, plant and equipment of $33 million, $31 million and $31 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 2013, 2012 and 2011, Virginia Power recorded $32 million, $37 million and $20 million of AFUDC related to these projects, respectively.

For property subject to cost-of-service rate regulation, including Virginia Power 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 average composite depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2013	2012	2011
(percent)
Dominion
Generation	2.71	2.62	2.68
Transmission	2.36	2.17	2.26
Distribution	3.13	3.17	3.19
Storage	2.43	2.59	2.64
Gas gathering and processing	2.39	2.49	2.52
General and other	3.82	4.55	4.66
Virginia Power
Generation	2.71	2.62	2.68
Transmission	2.28	1.98	2.03
Distribution	3.33	3.32	3.33
General and other	3.51	4.32	4.38

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	44 years
Merchant generation-other	15-36 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.

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. At least annually, the Companies evaluate the key assumptions underlying their AROs including estimates of the amounts and timing of future cash flows associated with retirement activities. AROs are adjusted when significant changes in these assumptions are identified. Dominion reports accretion of AROs and depreciation on asset retirement costs 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 and depreciation on asset retirement costs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs is reported in other operations and maintenance expense and depreciation 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 AOCI. 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 $7 million and $24 million at December 31, 2013 and December 31, 2012, respectively. Based on the average price of gas purchased during 2013 and 2012, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $77 million and $69 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.

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Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013:

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	100.00
6.98	600	100.00
Flex Money Market Preferred 12/02, Series A	1,250	100.00		(1)
Total	2,590

(1) Effective March 20, 2011 the rate was reset to 6.12% until March 20, 2014 after which the rate

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Income Taxes (The Companies Deferred Income Taxes Components) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Tax Contingency [Line Items]
Total deferred income tax assets	$ 2,142	$ 2,505
Total deferred income tax liabilities	8,463	7,716
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	5,383	4,601
Nuclear decommissioning	1,136	994
Deferred state income taxes	606	474
Federal benefit of deferred state income taxes	(212)	(166)
Deferred fuel, purchased energy and gas costs	(33)	3
Pension benefits	435	231
Other postretirement benefits	(78)	(171)
Loss and credit carryforwards	(797)	(656)
Valuation allowances	69	93
Partnership basis differences	125	174
Other	(313)	(366)
Total net deferred income tax liabilities	6,321	5,211
Virginia Electric and Power Company
Income Tax Contingency [Line Items]
Total deferred income tax assets	462	466
Total deferred income tax liabilities	4,498	4,238
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	3,628	3,394
Nuclear decommissioning	441	407
Deferred state income taxes	285	265
Federal benefit of deferred state income taxes	(100)	(93)
Deferred fuel, purchased energy and gas costs	(50)	(16)
Pension benefits	(52)	(17)
Other postretirement benefits	(3)	(7)
Loss and credit carryforwards	(106)	(77)
Valuation allowances	0	0
Partnership basis differences	0	0
Other	(7)	(84)
Total net deferred income tax liabilities	$ 4,036	$ 3,772

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Preferred Stock Preferred Stock (Schedule of Preferred Stock) (Details) (Virginia Electric and Power Company, USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013 $5.00	Dec. 31, 2013 $4.04	Dec. 31, 2013 $4.20	Dec. 31, 2013 $4.12	Dec. 31, 2013 $4.80	Dec. 31, 2013 $7.05	Dec. 31, 2013 $6.98	Dec. 31, 2013 Flex Money Market Preferred 12/02, Series A		Feb. 28, 2014 Flex Money Market Preferred 12/02, Series A Subsequent Event
Class of Stock [Line Items]
Dividend		$ 5.00	$ 4.04	$ 4.20	$ 4.12	$ 4.80	$ 7.05	$ 6.98
Issued and Outstanding Shares	2,590	107	13	15	32	73	500	600	1,250
Entitled Per Share Upon Liquidation	$ 100.00	$ 112.50	$ 102.27	$ 102.50	$ 103.73	$ 101.00	$ 100.00	$ 100.00	$ 100.00	[1]	$ 100.00	[1]
Dividend rate	6.12%

[1] Effective March 20, 2011 the rate was reset to 6.12% until March 20, 2014 after which the rate was due to be reset through an auction process. However, in February 2014, Virginia Power provided irrevocable notice to redeem the stock on March 20, 2014 at a price of $100 per share plus accumulated and unpaid dividends.

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Dispositions (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended		1 Months Ended	6 Months Ended	12 Months Ended		1 Months Ended		1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2013 Illinois Gas Contracts	Jun. 30, 2013 Brayton Point and Kincaid	Dec. 31, 2013 Brayton Point and Kincaid	Dec. 31, 2013 Loss from Discontinued Operations Brayton Point and Kincaid	Aug. 31, 2013 Elwood	Dec. 31, 2013 Elwood	Aug. 31, 2013 Elwood Other Income
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales price			$ 32
Gain on sale			29
After-tax gain on sale			18
Asset disposition adjustment	44	11	3			16
Impairment charge	1,600			48	1,600
Long-lived assets impairment charges, net of tax				28
Ownership percentage								50.00%
Proceeds from sale of equity method investment							465
Gain on sale of investment									35
After tax gain on sale of investment									25
Loss from discontinued operation					(17)
Loss on discontinued operation, net of tax					$ (18)

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Goodwill And Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2013

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(1)		Total
(millions)
Balance at December 31, 2011(2)	$	1,503		(3)	$	712			$	926	(3)	$	—	$	3,141
Asset disposition adjustment	—				(11		)	(5)	—			—		(11		)
Balance at December 31, 2012(2)	$	1,503			$	701			$	926		$	—	$	3,130
Asset disposition adjustment	(19		)	(4)	(25		)	(5)	—			—		(44		)
Balance at December 31, 2013(2)	$	1,484			$	676			$	926		$	—	$	3,086

(1) Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.

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

(3) Recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

(4) See Note 3 for a discussion of Dominion's dispositions and related goodwill write-offs.

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

Components of intangible assets

The components of intangible assets are as follows:

At December 31,	2013				2012
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion
Software, licenses and other	$	867	$	308	$	859	$	327
Emissions allowances	3		2		5		1
Total	$	870	$	310	$	864	$	328
Virginia Power
Software, licenses and other	$	271	$	78	$	303	$	122
Total	$	271	$	78	$	303	$	122

Annual amortization expense of intangible assets

Annual amortization expense for these intangible assets is estimated to be as follows:

	2014		2015		2016		2017		2018
(millions)
Dominion	$	69	$	59	$	50	$	40	$	29
Virginia Power	$	21	$	15	$	12	$	9	$	5

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Consolidated Statements of Equity (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Preferred dividends related to noncontrolling interest	$ 17	$ 16	$ 17
Shares issued in excess of principal amounts related to converted securities	$ 28

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Related Party Transactions (Details) (Virginia Electric and Power Company, USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Commodity purchases from affiliates		$ 417	$ 368	$ 376
Services provided by affiliates		415	399	393
Services provided to affiliates		21	19	21
Purchased nuclear fuel-related inventory	39
Outstanding borrowings, net of repayments, under the Dominion money pool for Virginia Power's nonregulated subsidiaries			192
Dominion
Related Party Transaction [Line Items]
Short term demand note borrowings		$ 97	$ 243

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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, 2013	Dec. 31, 2011	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding and exercisable beginning, Shares	628
Exercised, Shares	(622)		(1,174)
Forfeited/expired, Shares	(6)		(8)
Outstanding and exercisable ending, Shares	0	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
Exercised, Weighted-average Exercise Price	$ 30.79	$ 32.46
Forfeited/expired, Weighted-average Exercise Price	$ 32.26	$ 31.57
Outstanding and exercisable ending, Weighted-average Exercise Price	$ 0.00	$ 31.76
Outstanding and exercisable beginning, Aggregated Intrinsic Value	$ 14
Exercised, Aggregated Intrinsic Value	13		17
Outstanding and exercisable ending, Aggregated Intrinsic Value	$ 0	$ 20

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Dispositions (Schedule of Disposal Groups, Including Discontinued Operations, Income Statement) (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment charge		$ 1,600
Brayton Point and Kincaid
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenue		304		258		380
Loss before income taxes		(135)	[1]	(1,768)	[2]	(57)
Charges related to early redemption of debt		(64)
Impairment charge	48	1,600
State Line and Salem Harbor
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenue				57		233
Loss before income taxes				(49)		(34)
Impairment charge						$ 55

[1] Includes $64 million of charges related to the defeasance of Brayton Point debt and the early redemption of Kincaid debt in 2013. See Note 17 for more information.

[2] Includes a long-lived asset impairment charge of $1.6 billion.

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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, 2013
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Effect of one percentage point increase on total of service and interest cost components	$ 16
Effect of one percentage point increase on other postretirement benefit obligation	140
Effect of one percentage point decrease on total of service and interest cost components	(18)
Effect of one percentage point decrease on other postretirement benefit obligation	$ (118)

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Commitments and Contingencies (Guarantees, Surety Bonds and Letters of Credit) (Narrative) (Details) (USD $)	Dec. 31, 2013
Guarantor Obligations [Line Items]
Exposure under guarantees	$ 4,421,000,000
Purchased surety bonds	147,000,000
Standby Letters of Credit
Guarantor Obligations [Line Items]
Authorized standby letters of credit with financial institutions	11,000,000
Minimum
Guarantor Obligations [Line Items]
Annual future contributions	4,000,000
Maximum
Guarantor Obligations [Line Items]
Annual future contributions	19,000,000
Third Party and Equity Method Investee
Guarantor Obligations [Line Items]
Estimate of possible loss	69,000,000
Exposure under guarantees	39,000,000
Third Party and Equity Method Investee | Through 2019
Guarantor Obligations [Line Items]
Exposure under guarantees	90,000,000
Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Purchased Surety Bonds	59,000,000
Authorized issuance of standby letters of credit	1,000,000
Virginia Electric and Power Company | Tax-Exempt Financings
Guarantor Obligations [Line Items]
Estimate of possible loss	$ 14,000,000

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Derivatives and Hedge Accounting Activities (Tables)

12 Months Ended

Dec. 31, 2013

Derivative [Line Items]

Offsetting Assets

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

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	137	$	—	$	137	$	93	$	—	$	93
Commodity contracts:
Over-the-counter	240		—		240		290		—		290
Exchange	506		—		506		416		—		416
Total derivatives, subject to a master netting or similar arrangement	883		—		883		799		—		799
Total derivatives, not subject to a master netting or similar arrangement	7		—		7		29		—		29
Total(1)	$	890	$	—	$	890	$	828	$	—	$	828

(1) At December 31, 2013, the total derivative asset balance contains $687 million of current assets, which is presented in current derivative assets, in Dominion’s Consolidated Balance Sheet, and $203 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $518 million of current assets, which is presented in current derivative assets in Dominion’s Consolidated Balance Sheet and $310 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet.

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	137	$	—	$	—	$	137	$	93	$	19	$	—	$	74
Commodity contracts:
Over-the-counter	240		63		—		177		290		97		—		193
Exchange	506		505		—		1		416		350		4		62
Total	$	883	$	568	$	—	$	315	$	799	$	466	$	4	$	329

Offsetting Liabilities

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	66	$	—	$	66
Commodity contracts:
Over-the-counter	262		—		262		191		—		191
Exchange	838		—		838		393		—		393
Total derivatives, subject to a master netting or similar arrangement	1,100		—		1,100		650		—		650
Total derivatives, not subject to a master netting or similar arrangement	2		—		2		11		—		11
Total(1)	$	1,102	$	—	$	1,102	$	661	$	—	$	661

(1) At December 31, 2013, the total derivative liability balance contains $828 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet, and $274 million of noncurrent liabilities, which is presented in the other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $510 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet and $151 million of noncurrent liabilities, which is presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet.

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	—	$	66	$	19	$	—	$	47
Commodity contracts:
Over-the-counter	262		63		69		130		191		97		20		74
Exchange	838		505		333		—		393		350		43		—
Total	$	1,100	$	568	$	402	$	130	$	650	$	466	$	63	$	121

Volumes of Derivatives

The following table presents the volume of Dominion's derivative activity as of December 31, 2013. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)	116		19
Basis(1)	466		281
Electricity (MWh):
Fixed price(1)	14,814,767		14,935,144
FTRs	41,316,345		437,384
Capacity (MW)	83,050		18,300
Liquids (gallons)(2)	151,200,000		—
Interest rate	$	2,050,000,000	$	750,000,000

(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, 2013:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(3	)	$	(3	)	28 months
Electricity	(172		)	(124		)	36 months
Other	(3		)	(3		)	29 months
Interest rate	(110		)	(7		)	364 months
Total	$	(288	)	$	(137	)

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:

	Fair Value  - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At December 31, 2013
ASSETS
Current Assets
Commodity	$	49	$	522	$	571
Interest rate	116		—		116
Total current derivative assets	165		522		687
Noncurrent Assets
Commodity	28		154		182
Interest rate	21		—		21
Total noncurrent derivative assets(1)	49		154		203
Total derivative assets	$	214	$	676	$	890
LIABILITIES
Current Liabilities
Commodity	$	267	$	561	$	828
Total current derivative liabilities	267		561		828
Noncurrent Liabilities
Commodity	119		155		274
Total noncurrent derivative liabilities(2)	119		155		274
Total derivative liabilities	$	386	$	716	$	1,102
At December 31, 2012
ASSETS
Current Assets
Commodity	$	103	$	379	$	482
Interest rate	36		—		36
Total current derivative assets	139		379		518
Noncurrent Assets
Commodity	130		123		253
Interest rate	57		—		57
Total noncurrent derivative assets(1)	187		123		310
Total derivative assets	$	326	$	502	$	828
LIABILITIES
Current Liabilities
Commodity	$	103	$	341	$	444
Interest rate	66		—		66
Total current derivative liabilities	169		341		510
Noncurrent Liabilities
Commodity	58		93		151
Total noncurrent derivative liabilities(2)	58		93		151
Total derivative liabilities	$	227	$	434	$	661

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

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

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	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)
Year Ended December 31, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	(58	)
Purchased gas				(47		)
Electric fuel and other energy-related purchases				(10		)
Total commodity	$	(481	)	$	(115	)	$	5
Interest rate(3)	77			(15		)	81
Total	$	(404	)	$	(130	)	$	86
Year Ended December 31, 2012
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	)

(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.

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,	2013			2012			2011
(millions)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue	$	(45	)	$	168		$	111
Purchased gas	(9		)	(14		)	(35		)
Electric fuel and other energy-related purchases	(29		)	(40		)	(45		)
Interest rate(2)	—			17			(5		)
Total	$	(83	)	$	131		$	26

(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]

Offsetting Assets

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

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	48	$	—	$	48	$	—	$	—	$	—
Commodity contracts:
Over-the-counter	4		—		4		6		—		6
Exchange	1		—		1		—		—		—
Total derivatives, subject to a master netting or similar arrangement	53		—		53		6		—		6
Total derivatives, not subject to a master netting or similar arrangement	—		—		—		—		—		—
Total(1)	$	53	$	—	$	53	$	6	$	—	$	6

(1) At December 31, 2013, the total derivative asset balance contains $53 million of current assets, which is presented in other current assets in Virginia Power’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $6 million of current assets, which is presented in other current assets in Virginia Power’s Consolidated Balance Sheet.

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	48	$	—	$	—	$	48	$	—	$	—	$	—	$	—
Commodity contracts:
Over-the-counter	4		4		—		—		6		3		—		3
Exchange	1		—		—		1		—		—		—		—
Total	$	53	$	4	$	—	$	49	$	6	$	3	$	—	$	3

Offsetting Liabilities

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	25	$	—	$	25
Commodity contracts:
Over-the-counter	12		—		12		7		—		7
Exchange	—		—		—		2		—		2
Total derivatives, subject to a master netting or similar arrangement	12		—		12		34		—		34
Total derivatives, not subject to a master netting or similar arrangement	—		—		—		—		—		—
Total(1)	$	12	$	—	$	12	$	34	$	—	$	34

(1) At December 31, 2013, the total derivative liability balance contains $12 million of current liabilities, which is presented in current derivative liabilities in Virginia Power’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $33 million of current liabilities, which is presented in current derivative liabilities in Virginia Power’s Consolidated Balance Sheet and $1 million of noncurrent derivative liabilities, which is presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheet.

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	—	$	25	$	—	$	—	$	25
Commodity contracts:
Over-the-counter	12		4		7		1		7		3		—		4
Exchange	—		—		—		—		2		—		2		—
Total	$	12	$	4	$	7	$	1	$	34	$	3	$	2	$	29

Volumes of Derivatives

The following table presents the volume of Virginia Power's derivative activity at December 31, 2013. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price	15		—
Basis	7		—
Electricity (MWh):
Fixed price	624,800		—
FTRs	39,186,609		—
Capacity (MW)	75,500		18,300
Interest rate	$	600,000,000	$	—

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:

	Fair Value  - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At December 31, 2013
ASSETS
Current Assets
Commodity	$	2	$	3	$	5
Interest rate	48				48
Total current derivative assets(1)	50		3		53
Total derivative assets	$	50	$	3	$	53
LIABILITIES
Current Liabilities
Commodity	$	1	$	11	$	12
Total current derivative liabilities	1		11		12
Total derivative liabilities	$	1	$	11	$	12
At December 31, 2012
ASSETS
Current Assets
Commodity	$	1	$	5	$	6
Total current derivative assets(1)	1		5		6
Total derivative assets	$	1	$	5	$	6
LIABILITIES
Current Liabilities
Commodity	$	5	$	3	$	8
Interest rate	25		—		25
Total current derivative liabilities	$	30	$	3	$	33
Noncurrent Liabilities
Commodity	1		—		1
Total noncurrent derivative liabilities(2)	1		—		1
Total derivative liabilities	$	31	$	3	$	34

(1) Current derivative assets are presented in other current assets in Virginia Power's Consolidated Balance Sheets.

(2) 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	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)
Year Ended December 31, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	—
Total commodity	$	—		$	—		$	5
Interest rate(3)	9			—			81
Total	$	9		$	—		$	86
Year Ended December 31, 2012
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	)

(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.

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,	2013			2012			2011
(millions)
Derivative Type and Location of Gains (Losses)
Commodity(2)	$	(16	)	$	(50	)	$	(45	)
Interest rate(3)	—			—			(5		)
Total	$	(16	)	$	(50	)	$	(50	)

(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.

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Shareholders' Equity

12 Months Ended

Dec. 31, 2013

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.  In January 2014, Dominion began purchasing its common stock on the open market for these plans.

During 2013, Dominion issued approximately 5.4 million shares of common stock through various programs.  Dominion received cash proceeds of $278 million from the issuance of 4.7 million of such shares through Dominion Direct and employee savings plans.

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 $317 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 2013. 

VIRGINIA POWER

In 2013, 2012 and 2011, Virginia Power did not issue any shares of its common stock to Dominion.

Shares Reserved for Issuance

At December 31, 2013, Dominion had approximately 48 million shares reserved and available for issuance for Dominion Direct^®, employee stock awards, employee savings plans, director stock compensation plans, contingent convertible senior notes and issuance in connection with stock purchase contracts. See Note 17 for more information.

Repurchase of Common Stock

Dominion did not repurchase any shares in 2013 or 2012 and does not plan to repurchase shares during 2014, except for shares tendered by employees to satisfy tax withholding obligations on vested restricted stock and purchases of common stock on the open market in 2014 for direct stock purchase plans, 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,	2013			2012
(millions)
Dominion
Net deferred losses on derivatives-hedging activities, net of tax of $196 and $87	$	(288	)	$	(122	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(307) and $(206)	474			326
Net unrecognized pension and other postretirement benefit costs, net of tax of $365 and $745	(510		)	(1,081		)
Total AOCI	$	(324	)	$	(877	)
Virginia Power
Net deferred losses on derivatives-hedging activities, net of tax of $-- and $3	$	—		$	(6	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(30) and $(19)	48			31
Total AOCI	$	48		$	25

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

	Deferred gains and losses on derivatives-hedging activities			Unrealized gains and losses on investment securities			Unrecognized pension and other postretirement benefit costs			Total
(millions)
Year Ended December 31, 2013
Beginning balance	$	(122	)	$	326		$	(1,081	)	$	(877	)
Other comprehensive income before reclassifications: gains (losses)	(243		)	203			516			476
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)	77			(55		)	55			77
Net current period other comprehensive income (loss)	(166		)	148			571			553
Ending balance	$	(288	)	$	474		$	(510	)	$	(324	)

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

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

Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Year Ended December 31, 2013
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	58		Operating revenue
	47			Purchased gas
	10			Electric fuel and other energy-related purchases
Interest rate contracts	15			Interest and related charges
Total	130
Tax	(53		)	Income tax expense
Total, net of tax	$	77
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(98	)	Other income
Impairment	8			Other income
Total	(90		)
Tax	35			Income tax expense
Total, net of tax	$	(55	)
Unrecognized pension and other postretirement benefit costs:
Prior-service costs (credits)	$	(8	)	Other operations and maintenance
Actuarial losses	102			Other operations and maintenance
Total	94
Tax	(39		)	Income tax expense
Total, net of tax	$	55

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

	Deferred gains and losses on derivatives-hedging activities			Unrealized gains and losses on nuclear decommissioning trust funds			Total
(millions)
Year Ended December 31, 2013
Beginning balance	$	(6	)	$	31		$	25
Other comprehensive income before reclassifications: gains (losses)	6			20			26
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)	—			(3		)	(3		)
Net current period other comprehensive income (loss)	6			17			23
Ending balance	$	—		$	48		$	48

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

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

Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Year Ended December 31, 2013
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(6	)	Other income
Impairment	1			Other income
Total	(5		)
Tax	2			Income tax expense
Total, net of tax	$	(3	)

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, 2013, 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, 2013, 2012 and 2011 include $31 million, $25 million, and $39 million,respectively, of compensation costs and $11 million, $8 million, and $13 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, 2013, 2012, and 2011, Dominion realized less than $1 million, $10 million and $2 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 and 2011. There were no stock options outstanding in 2013. No options were granted under any plan in 2013, 2012 or 2011.

	Shares		Weighted - average Exercise Price		Weighted - average Remaining Contractual Life	Aggregated Intrinsic Value(1)
	(thousands)				(years)	(millions)
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 any stock option exercises. Dominion received cash proceeds from the exercise of stock options of approximately $19 million, and $38 million in the years ended December 31, 2012 and 2011, respectively.

RESTRICTED STOCK

Restricted stock grants are made to officers under Dominion's LTIP and may also be granted to certain key non-officer employees from time to time. The fair value of Dominion's restricted stock awards is equal to the closing 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, 2013, 2012 and 2011:

	Shares		Weighted - average Grant Date Fair Value
	(thousands)
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
Granted	312		54.70
Vested	(356	)	39.00
Cancelled and forfeited	(34	)	51.11
Nonvested at December 31, 2013	1,007		$	49.35

As of December 31, 2013, unrecognized compensation cost related to nonvested restricted stock awards totaled $21 million and is expected to be recognized over a weighted-average period of 1.8 years. The fair value of restricted stock awards that vested was $20 million, $30 million, and $28 million in 2013, 2012 and 2011, 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 2012 and February 2013.

The issuance of awards is based on the achievement of two performance metrics during a two-year period: TSR relative to that of companies listed as members of the Philadelphia 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 closing 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 February 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.

After the performance period for the February 2011 grants ended on December 31, 2012, the CGN Committee determined the actual performance against metrics established for those awards. For awards to officers, 3 thousand shares of the outstanding goal-based stock awards were converted to 2 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, 2013, 2012 and 2011:

	Targeted Number of Shares		Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2010	161		$	31.79
Granted	3		43.54
Vested	(20	)	34.62
Cancelled and forfeited	(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
Granted	4		54.17
Vested	(2	)	43.54
Cancelled and forfeited	(1	)	43.54
Nonvested at December 31, 2013	5		$	53.85

At December 31, 2013, the targeted number of shares expected to be issued under the February 2012 and February 2013 awards was approximately 5 thousand. In January 2014, the CGN Committee determined the actual performance against metrics established for the February 2012 awards with a performance period that ended December 31, 2013. Based on that determination, the total number of shares to be issued under the February 2012 goal-based stock awards was approximately 1 thousand.

As of December 31, 2013, 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.

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.

In February 2011, a cash-based performance grant was made to officers. A portion of the grant, representing $6 million was paid in December 2012, based on the achievement of two performance metrics during 2011 and 2012: ROIC and TSR relative to that of a peer group of companies. The total amount of the award under the grant was $8 million and the remaining $2 million of the grant was paid in February 2013.

In February 2012, a cash-based performance grant was made to officers. A portion of the grant, representing the initial payout of $8 million was paid in December 2013, based on the achievement of two performance metrics during 2012 and 2013: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total expected award under the grant is $12 million and the remaining portion of the grant is expected to be paid by March 15, 2014. At December 31, 2013, a liability of $4 million had been accrued for the remaining portion of the award.

In February 2013, a cash-based performance grant was made to officers. Payout of the performance grant is expected to occur by March 15, 2015 based on the achievement of two performance metrics during 2013 and 2014: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. At December 31, 2013, the targeted amount of the grant was $13 million and a liability of $6 million had been accrued for this award.

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Preferred Stock

12 Months Ended

Dec. 31, 2013

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, 2013 or 2012.

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, 2013 and 2012. 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, 2013:

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	100.00
6.98	600	100.00
Flex Money Market Preferred 12/02, Series A	1,250	100.00		(1)
Total	2,590

(1) Effective March 20, 2011 the rate was reset to 6.12% until March 20, 2014 after which the rate was due to be reset through an auction process. However, in February 2014, Virginia Power provided irrevocable notice to redeem the stock on March 20, 2014 at a price of $100 per share plus accumulated and unpaid dividends.

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Regulatory Matters (Narrative) (Details) (USD $)	12 Months Ended			1 Months Ended		3 Months Ended	12 Months Ended					1 Months Ended		12 Months Ended	1 Months Ended					12 Months Ended	1 Months Ended												1 Months Ended		12 Months Ended	1 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	May 31, 2012 Virginia Electric and Power Company	Mar. 31, 2010 Virginia Electric and Power Company	Dec. 31, 2013 Virginia Electric and Power Company	Dec. 31, 2013 Virginia Electric and Power Company	Dec. 31, 2012 Virginia Electric and Power Company	Dec. 31, 2011 Virginia Electric and Power Company	Sep. 01, 2008 Virginia Electric and Power Company Project	Jul. 31, 2008 Virginia Electric and Power Company Project	Nov. 30, 2013 Virginia Electric and Power Company Virginia Regulation	May 31, 2013 Virginia Electric and Power Company Virginia Regulation	Dec. 31, 2013 Virginia Electric and Power Company Virginia Regulation	Oct. 31, 2013 Virginia Electric and Power Company Loudoun- Pleasant View Transmission Virginia Regulation kV	Nov. 30, 2013 Virginia Electric and Power Company Surry Switching Station Transmission Line Virginia Regulation kV	Nov. 30, 2013 Virginia Electric and Power Company Transmission Line from Skiffes Creek Switching Station to Wheaton Substation Virginia Regulation kV mi	Sep. 30, 2013 Virginia Electric and Power Company Bremo Power Station Virginia Regulation MW	Jul. 31, 2013 Virginia Electric and Power Company North Anna Virginia Regulation Part	Dec. 31, 2013 Virginia Electric and Power Company North Anna Virginia Regulation	Nov. 30, 2013 Virginia Electric and Power Company Minimum Surry Switching Station Transmission Line Virginia Regulation mi	Jun. 30, 2013 Virginia Electric and Power Company Rider B Virginia Regulation	Nov. 30, 2013 Virginia Electric and Power Company Rider BW Virginia Regulation	Jun. 30, 2013 Virginia Electric and Power Company Rider S Virginia Regulation	May 31, 2013 Virginia Electric and Power Company Rider W Virginia Regulation	Aug. 31, 2013 Virginia Electric and Power Company Rider C1A Virginia Regulation	Aug. 31, 2013 Virginia Electric and Power Company Rider C2A Virginia Regulation	May 31, 2013 Virginia Electric and Power Company Rider T1 Virginia Regulation	Jul. 31, 2008 Virginia Electric and Power Company 1.5% Incentive rate for projects Project	Jul. 31, 2008 Virginia Electric and Power Company 1.25% Incentive rate for projects Project	Dec. 31, 2013 Virginia Electric and Power Company Other Current Liabilities Virginia Regulation	Dec. 31, 2013 Virginia Electric and Power Company Noncurrent Regulatory Liability Virginia Regulation	Nov. 30, 2013 East Ohio PIR Program Ohio Regulation	Feb. 28, 2013 East Ohio PIR Program Ohio Regulation	Dec. 31, 2008 East Ohio PIR Program Ohio Regulation mi	Mar. 31, 2013 East Ohio PIPP Plus Program Ohio Regulation	Mar. 31, 2013 East Ohio PIPP Plus Program Ohio Regulation Scenario, Forecast	Dec. 31, 2013 DTI
Regulatory Matters [Line Items]
Approved ROE							11.40%					10.90%		10.00%
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							857,000,000
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
Earned ROE percentage												10.25%		10.30%
Basis points below authorized ROE												0.50%
Amount of deferred recovery costs authorized												23,000,000
Amount of revenue sufficiency												280,000,000
Charge related to Biennial Review Order														55,000,000
Restoration costs net of tax						28,000,000								37,000,000
Peer group floor ROE, percentage														9.89%
Market cost of equity, percentage														10.00%
Proposed increase decrease revenue requirement													162,000,000
Approved fuel factor rate												0.02942
Requested fuel factor rate												0.02572
Amount of expected reduction in anticipated fuel recoveries												140,000,000
Liabilities related to fuel recoveries																															24,000,000	85,000,000
Proposed revenue requirement																						16,000,000		248,000,000	101,000,000			404,000,000
Proposed revenue requirement																							101,000,000			1,000,000	35,000,000
Capacity of Electricity (in Megawatts)																		227
Expected cost of proposed conversion																		53,000,000
Number of parts of amendment to COL application																			2
Period after completion of seismic assessment to submit motion to reopen proceeding																				60 days
Percentage of development costs incurred that are recoverable through future rate adjustment clause																				30.00%
Plant construction and other property additions (including nuclear fuel)	4,104,000,000	4,145,000,000	3,652,000,000				2,394,000,000	2,082,000,000	1,885,000,000											570,000,000
Projected amount of capitalized costs recovered, percentage																				70.00%
KV Line															500	500	230
Length of Transmission line																	20				7
Percentage replacement of pipeline system																																			20.00%
Miles of pipeline identified to be replaced																																			4,100
Period for pipeline replacement																																			25 years
Total plant investment																																	170,000,000	148,000,000
Cumulative gross plant investment																																	681,000,000	511,000,000
Approved revenue requirement																																	90,000,000	67,000,000
Refund of overrecovery of accumulated arrearages																																				91,000,000
Recovery of projected deferred program costs																																					54,000,000
Amount that agreement could reduce revenues																																						$ 35,000,000

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Related Party Transactions (Tables) (Virginia Electric and Power Company)

12 Months Ended

Dec. 31, 2013

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,	2013		2012		2011
(millions)
Commodity purchases from affiliates	$	417	$	368	$	376
Services provided by affiliates	415		399		393
Services provided to affiliates	21		19		21

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share Computation

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

	2013		2012		2011
(millions, except EPS)
Net income attributable to Dominion	$	1,697	$	302	$	1,408
Average shares of common stock outstanding-Basic	578.7		572.9		573.1
Net effect of dilutive securities(1)	0.8		1.0		1.5
Average shares of common stock outstanding-Diluted	579.5		573.9		574.6
Earnings Per Common Share-Basic	$	2.93	$	0.53	$	2.46
Earnings Per Common Share-Diluted	$	2.93	$	0.53	$	2.45

(1) Dilutive securities consist primarily of contingently convertible senior notes. See Note 17 for more information.

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Dividend Restrictions

12 Months Ended

Dec. 31, 2013

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, 2013, 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, 2013.

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 and equity units, initially in the form of corporate units.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2013

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 $959 million in 2013 and $743 million in 2012, versus expected returns of $554 million and $509 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.

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 2013 and 2012. Effective January 1, 2013, Dominion changed 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 reduced other postretirement benefit costs by approximately $20 million annually beginning in 2012. As a result of the adoption of the EGWP, Dominion will begin to receive an increased level of Medicare Part D subsidies, in the form of reduced costs rather than a direct reimbursement, over the next few years.

Dominion remeasured all of its pension and other postretirement benefit plans in the second quarter of 2013. The remeasurement resulted in a reduction in the pension benefit obligation of approximately $354 million and a reduction in the accumulated postretirement benefit obligation of approximately $78 million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by approximately $36 million, excluding the impacts of curtailments. The discount rate used for the remeasurement was 4.80% for the pension plans and 4.70% for the other postretirement benefit plans. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.

In the fourth quarter of 2013, Dominion remeasured its other postretirement benefit plans as a result of a plan amendment that changed medical coverage for certain Medicare-eligible retirees effective April 2014. The remeasurement resulted in a reduction in the accumulated postretirement benefit obligation of approximately $220 million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date and reduced net periodic benefit cost for 2013 by approximately $8 million. The amendment is expected to reduce net periodic benefit cost by $40 million to $60 million for each of the next five years. The discount rate used for the remeasurement was 4.80%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2012.

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,	2013			2012			2013			2012
(millions, except percentages)
Changes in benefit obligation:
Benefit obligation at beginning of year	$	6,125		$	4,981		$	1,719		$	1,493
Service cost	131			116			43			44
Interest cost	271			268			73			79
Benefits paid	(229		)	(208		)	(75		)	(88		)
Actuarial (gains) losses during the year	(650		)	967			(170		)	191
Plan amendments(1)	1			1			(220		)	1
Settlements and curtailments(2)	(24		)	—			(16		)	(6		)
Special termination benefits	—			—			1			—
Medicare Part D reimbursement	—			—			5			5
Benefit obligation at end of year	$	5,625		$	6,125		$	1,360		$	1,719
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	5,553		$	5,145		$	1,156		$	1,042
Actual return on plan assets	781			611			178			132
Employer contributions	8			5			12			16
Benefits paid	(229		)	(208		)	(31		)	(34		)
Fair value of plan assets at end of year	$	6,113		$	5,553		$	1,315		$	1,156
Funded status at end of year	$	488		$	(572	)	$	(45	)	$	(563	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	913		$	701		$	29		$	1
Other current liabilities	(15		)	(2		)	(3		)	(4		)
Noncurrent pension and other postretirement benefit liabilities	(410		)	(1,271		)	(71		)	(560		)
Net amount recognized	$	488		$	(572	)	$	(45	)	$	(563	)
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate(3)	5.20%/5.30%			4.40		%	5.00%/5.10%			4.40		%
Weighted average rate of increase for compensation	4.21		%	4.21		%	4.22		%	4.22		%

(1) Relates to a plan amendment that changed medical coverage for certain Medicare-eligible retirees.

(2) 2013 amounts relate primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor.

(3) Pension rates are 5.20% for the gas union plans and 5.30% for the nonunion and other union plans. OPEB rates are 5.00% for the gas union plans and 5.10% for the nonunion and other union plans.

The ABO for all of Dominion's defined benefit pension plans was $5.1 billion and $5.5 billion at December 31, 2013 and 2012, 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 2013, Dominion made no contributions to its qualified defined benefit pension plans and no contributions are currently expected in 2014. 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 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 $12 million to the Dominion VEBAs in 2014.

Dominion does not expect any pension or other postretirement plan assets to be returned to the Company during 2014.

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,	2013		2012		2013		2012
(millions)
Benefit obligation	$	4,978	$	5,462	$	1,233	$	1,591
Fair value of plan assets	4,553		4,189		1,158		1,027

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,	2013		2012
(millions)
Accumulated benefit obligation	$	114	$	4,850
Fair value of plan assets	—		4,189

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)
2014	$	264	$	91
2015	269		93
2016	283		96
2017	300		98
2018	319		100
2019-2023	1,868		507

Plan Assets

Dominion's overall objective for investing its pension and other postretirement plan assets is to achieve appropriate 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. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. 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. Common/collective trust funds are funds of grouped assets that follow various investment strategies. 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,	2013								2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	53	$	126	—		$	179	—		$	195	—		$	195
U.S. equity:
Large Cap	1,220		—		—		1,220		927		104		—		1,031
Other	514		—		—		514		425		99		—		524
Non-U.S. equity:
Large Cap	308		—		—		308		313		68		—		381
Other	391		—		—		391		228		167		—		395
Common/collective trust funds	—		1,387		—		1,387		—		—		—		—
Fixed income:
Corporate debt instruments	43		451		—		494		27		1,026		—		1,053
U.S. Treasury securities and agency debentures	2		229		—		231		331		304		—		635
State and municipal	69		107		—		176		1		71		—		72
Other securities	7		50		—		57		5		43		—		48
Real estate:
REITs	32		—		—		32		29		—		—		29
Partnerships	—		—		227		227		—		—		321		321
Other alternative investments:
Private equity	—		—		530		530		—		—		456		456
Debt	—		—		180		180		—		—		192		192
Hedge funds	—		—		187		187		—		—		221		221
Total	$	2,639	$	2,350	$	1,124	$	6,113	$	2,286	$	2,077	$	1,190	$	5,553

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,	2013								2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	3	$	14	$	—	$	17	$	—	$	13	$	—	$	13
U.S. equity:
Large Cap	472		—		—		472		378		5		—		383
Other	26		—		—		26		21		45		—		66
Non-U.S. equity:
Large Cap	111		—		—		111		93		3		—		96
Other	20		—		—		20		11		8		—		19
Common/collective trust funds	—		502		—		502		—		—		—		—
Fixed income:
Corporate debt instruments	2		23		—		25		1		160		—		161
U.S. Treasury securities and agency debentures	—		12		—		12		16		266		—		282
State and municipal	4		5		—		9		—		9		—		9
Other securities	—		3		—		3		—		2		—		2
Real estate:
REITs	2		—		—		2		1		—		—		1
Partnerships	—		—		19		19		—		—		24		24
Other alternative investments:
Private equity	—		—		60		60		—		—		58		58
Debt	—		—		27		27		—		—		31		31
Hedge funds	—		—		10		10		—		—		11		11
Total	$	640	$	559	$	116	$	1,315	$	521	$	511	$	124	$	1,156

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, 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
Actual return on plan assets:
Relating to assets still held at the reporting date	15			98			32			21			166			(2		)	6			3			1			8
Relating to assets sold during the period	(36		)	(48		)	(34		)	(4		)	(122		)	1			3			—			1			5
Purchases	6			115			32			—			153			1			7			2			—			10
Sales	(79		)	(91		)	(42		)	(51		)	(263		)	(5		)	(14		)	(9		)	(3		)	(31		)
Balance at December 31, 2013	$	227		$	530		$	180		$	187		$	1,124		$	19		$	60		$	27		$	10		$	116

Investments in Common/Collective Trust Funds in Dominion’s pension and other postretirement plans are stated at fair value as determined by the issuer of the Common/Collective Trust Funds based on the fair value of the underlying investments. The Common/Collective Trusts do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the Common/Collective Trust Funds have limited withdrawal or redemption rights during the term of the investment. Strategies of the Common/Collective Trust Funds are as follows:

• Wells Fargo Closed End Bond Trust-The Fund invests in stocks, bonds or a combination of both. Shares of the Fund are traded on a stock exchange and are subject to market risk like stocks, bonds and mutual funds. The Fund may invest in a less liquid portfolio of stocks and bonds because the fund does not need to sell securities to meet shareholder redemptions as mutual funds in order to keep a percentage of its portfolio in cash to pay back investors who withdraw shares.

• JPMorgan Core Bond Trust-The Fund seeks to maximize total return by investing primarily in a diversified portfolio of intermediate- and long-term debt securities. The Fund invests primarily in investment-grade bonds; it generally maintains an average weighted maturity between four and 12 years. It may shorten its average weighted maturity if deemed appropriate for temporary defensive purposes.

• SSgA Russell 2000 Value Index Common Trust-The Fund measures the performance of the small-cap value segment of the U.S. equity universe. The Russell 2000 Value Index is constructed to provide a comprehensive and unbiased barometer for the small-cap value segment. The Index is completely reconstituted annually to ensure larger stocks do not distort the performance and characteristics of the true small-cap opportunity set and that the represented companies continue to reflect value characteristics.

• SSgA Daily MSCI Emerging Markets Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI Emerging Markets Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company).

• SSgA Daily MSCI ACWI Ex-USA Index Non-Lending Fund-The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of the MSCI ACWI Ex-USA Index over the long term. The Fund may invest directly or indirectly in securities and other instruments, including in other pooled investment vehicles sponsored or managed by, or otherwise affiliated with the Trustee (State Street Bank and Trust Company).

• SSgA S&P 400 MidCap Index - The Fund seeks an investment return that approximates as closely as practicable, before expenses, the performance of its benchmark index (the Index) over the long term.  The S&P MidCap 400 is comprised of approximately 400 U.S. mid-cap securities and accounts for approximately 7% coverage of the U.S. stock market capitalization. SSgA will typically attempt to invest in the equity securities comprising the Index, in approximately the same proportions as they are represented in the Index.

• JPMorgan Chase Bank U.S. Active Core Plus Equity Fund-The Fund seeks to outperform the S&P 500 Index (the Benchmark), gross of fees, over a market cycle. The Fund invests primarily in a portfolio of long and short positions in equity securities of large and mid capitalization U.S. companies with characteristics similar to those of the Benchmark.

• Mondrian International Small Cap Equity Fund-The Fund’s investment objective is long-term total return. The Fund primarily invests in equity securities of non-U.S. small capitalization companies that, in the investment manager’s opinion, are undervalued at the time of purchase based on fundamental value analysis employed by the investment manager.

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,	2013			2012			2011			2013			2012			2011
(millions, except percentages)
Service cost	$	131		$	116		$	108		$	43		$	44		$	48
Interest cost	271			268			258			73			79			94
Expected return on plan assets	(462		)	(430		)	(440		)	(92		)	(79		)	(79		)
Amortization of prior service (credit) cost	3			3			3			(15		)	(13		)	(13		)
Amortization of net actuarial loss	165			132			96			7			6			12
Settlements and curtailments(1)	(2		)	—			—			(15		)	(4		)	1
Special termination benefits	—			—			—			1			—			—
Net periodic benefit cost	$	106		$	89		$	25		$	2		$	33		$	63
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	(968	)	$	786		$	534		$	(255	)	$	139		$	(157	)
Prior service (credit) cost	1			—			—			(215		)	1			(70		)
Settlements and curtailments(1)	(22		)	—			—			(7		)	(2		)	(1		)
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss	(165		)	(132		)	(96		)	(7		)	(6		)	(12		)
Amortization of prior service credit (cost)	(3		)	(3		)	(3		)	15			13			13
Total recognized in other comprehensive income and regulatory assets and liabilities	$	(1,157	)	$	651		$	435		$	(469	)	$	145		$	(227	)
Significant assumptions used to determine periodic cost:
Discount rate	4.40% - 4.80%			5.50		%	5.90		%	4.40% - 4.80%			5.50		%	5.90		%
Expected long-term rate of return on plan assets	8.50		%	8.50		%	8.50		%	7.75		%	7.75		%	7.75		%
Weighted average rate of increase for compensation	4.21		%	4.21		%	4.61		%	4.22		%	4.22		%	4.62		%
Healthcare cost trend rate(2)										7.00		%	7.00		%	7.00		%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(2)										4.60		%	4.60		%	4.60		%
Year that the rate reaches the ultimate trend rate(2)										2062			2061			2060

(1) 2013 amount relates primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor.

(2) 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 (credit) cost are as follows:

	Pension Benefits				Other Postretirement Benefits
At December 31,	2013		2012		2013			2012
(millions)
Net actuarial (gain) loss	$	1,709	$	2,865	$	(40	)	$	229
Prior service (credit) cost	10		11		(271		)	(71		)
Total(1)	$	1,719	$	2,876	$	(311	)	$	158

(1) As of December 31, 2013, of the $1.7 billion and $(311) million related to pension benefits and other postretirement benefits, $1.0 billion and $(156) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. 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.

The following table provides the components of AOCI and regulatory assets and liabilities as of December 31, 2013 that are expected to be amortized as components of periodic benefit cost in 2014:

	Pension Benefits		Other Postretirement Benefits
(millions)
Net actuarial loss	$	112	$	2
Prior service (credit) cost	3		(28		)

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 net periodic cost for 2014	$	16	$	(18	)
Effect on other postretirement benefit obligation at December 31, 2013	140		(118		)

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 2013, 2012 and 2011, Dominion recognized $40 million, $40 million and $38 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 2013 and 2012 Virginia Power made no contributions to the plan and no contributions are currently expected in 2014. Virginia Power's net periodic pension cost related to this pension plan was $96 million, $72 million and $50 million in 2013, 2012 and 2011, 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 $5 million, $13 million and $23 million in 2013, 2012 and 2011, 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. During 2013 and 2012, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2014.

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. During 2013, 2012 and 2011, Virgina Power recognized $16 million, $15 million and $14 million, respectively, as employer matching contributions to these plans.

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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, 2010		$ 11,997		$ 5,715	$ 194	$ 6,418		$ (330)	$ 11,997	$ 0	$ 8,507	$ 5,738	$ 1,111	$ 1,634	$ 24
Beginning Balance (in shares) at Dec. 31, 2010				581								275
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
Consolidation of non-controlling interests	[2]	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)	[3]			1
Stock repurchases, value	[3]	0		17	(17)				0
Tax benefit from stock awards and stock options exercised		2			2				2
Dividends		(1,151)				(1,146)	[4]		(1,146)	(5)	(574)			(574)
Tax benefit from stock awards and stock options exercised		13
Other comprehensive income, 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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests		501
Net income attributable to Dominion		494									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	[1]			318			318	11
Net income attributable to Dominion		302	[1]								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)	[3]			(1)
Other stock issuances, value	[3]	14		41	(27)				14
Tax benefit from stock awards and stock options exercised		10			10				10
Dividends		(1,236)				(1,225)	[4]		(1,225)	(11)	(575)			(575)
Tax benefit from stock awards and stock options exercised		8									2		2
Other comprehensive income, 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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests		502
Net income attributable to Dominion		495									287
Beginning Balance, value at Mar. 31, 2013
Beginning Balance, value at Dec. 31, 2012		10,625		5,493	162	5,790		(877)	10,568	57	9,233	5,738		2,357	25
Beginning Balance (in shares) at Dec. 31, 2012				576								275
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests		1,720				1,714			1,714	6
Net income attributable to Dominion		1,697									1,138			1,138
Consolidation of noncontrolling interests, (in shares)				4
Consolidation of noncontrolling interests, value		278		278					278
Stock awards and stock options exercised (net of change in unearned compensation), value		12		12					12
Other stock issuances (in shares)	[5]			(1)
Other stock issuances, value	[5]	7		15	(8)				7
Present value of stock purchase contract payments related to RSNs(5)	[6]	(156)			(154)	(2)			(156)
Fairless lease buyout	[7]	(72)		(15)					(15)	(57)
Dividends		(1,325)				(1,319)	[4]		(1,319)	(6)	(596)			(596)
Tax benefit from stock awards and stock options exercised		11
Other comprehensive income, net of tax		553						553	553		23				23
Beginning Balance, value at Dec. 31, 2013		11,642		5,783	0	6,183		(324)	11,642	0	9,798	5,738	1,113	2,899	48
Ending Balance (shares) at Dec. 31, 2013				581								275
Beginning Balance, value at Sep. 30, 2013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests	[8]	435
Net income attributable to Dominion		431	[8]								199
Beginning Balance, value at Dec. 31, 2013		$ 11,642									$ 9,798	$ 5,738	$ 1,113
Ending Balance (shares) at Dec. 31, 2013												275

[1] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

[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.

[4] Includes subsidiary preferred dividends related to noncontrolling interests of $17 million, $16 million and $17 million in 2013 and 2012 and 2011, respectively.

[5] Primarily includes $28 million in shares issued in excess of principal amounts related to converted securities. See Note 17 for further information on convertible securities.

[6] See Note 17 for further information.

[7] See Note 15 for further information.

[8] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

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. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies' maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on Dominion's or Virginia Power's financial position, liquidity or results of operations.

Environmental Matters

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. During the fourth quarter of 2013, Virginia Power recorded charges totaling $26 million ($16 million after-tax) for certain exit activities associated with these coal units, including the cost of employee severance, vendor contract termination, and inventory not expected to be used or usable at other stations.

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 were not material to Dominion. In August 2012, the court vacated CSAPR in its entirety and ordered the EPA to implement CAIR until a valid replacement rule is issued. In October 2012, the EPA filed a petition requesting a rehearing of the court's decision, which was denied in January 2013. The mandate vacating CSAPR was issued in February 2013. In March 2013, the EPA and several environmental groups filed petitions with the U.S. Supreme Court requesting review of the decision to vacate and remand CSAPR. In June 2013, the U.S. Supreme Court granted the EPA's petition seeking review of the D.C. Circuit's decision that vacated and remanded CSAPR. With respect to Dominion's generation fleet, the cost to comply with CAIR is not expected to be material. Future outcomes of litigation and/or any additional action to issue a revised rule could affect the assessment regarding cost of compliance.

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

In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerned historical operating changes and capital improvements undertaken at State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, NSPS, the Title V permit program and the stations' respective State Implementation Plans. In May 2010, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerned historical operating changes and capital improvements undertaken at Brayton Point.

Dominion believes that it complied with applicable laws and the EPA regulations and interpretations in effect at the time the work in question took place. Dominion entered into settlement discussions with the U.S. government and reached an agreement to settle the allegations. In April 2013, the U.S. government lodged a consent decree and complaint with the U.S. District Court for the Central District of Illinois that resolves all alleged violations at State Line, Kincaid and Brayton Point. The settlement mandates the closure of State Line, installation of certain control technology at Kincaid and Brayton Point, the achievement of certain emissions limitations, payment of a civil penalty of $3 million and funding of $10 million in environmental mitigation projects. In July 2013, the court entered the consent decree, concluding the enforcement action. Dominion previously accrued a liability of $13 million related to this matter.  State Line ceased operations in March 2012 and was sold in June 2012.  The installation of pollution control technology was in progress at Kincaid and had been completed at Brayton Point. In August 2013, Dominion sold Kincaid and Brayton Point. Under the terms of the sale transaction, Dominion retained the $13 million liability associated with the settlement agreement. Dominion has paid the civil penalty and is implementing the environmental mitigation projects.

WATER

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

In September 2010, Millstone's NPDES permit was reissued under the CWA. The conditions of the permit require an evaluation of control technologies that could result in additional expenditures in the future. The report summarizing the results 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. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. A remedy has not been selected. Due to the uncertainty surrounding the other sites, Dominion is unable to make an estimate of the potential financial statement impacts.

CLIMATE CHANGE LEGISLATION AND REGULATION

Massachusetts, Rhode Island, Connecticut, and Maryland, among other states, have joined RGGI, a multi-state effort to reduce CO₂ emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO₂ emissions from power plants in participating states are required to be stabilized at current levels from 2009 to 2015. Further reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO₂ emissions. During 2012, RGGI underwent a program review, and in February 2013, revisions to the RGGI model rule were issued that include a reduction of the regional CO₂ emissions cap from 165 million tons to 91 million tons beginning in January 2014, with an additional 2.5% reduction per year through 2020. The revisions also include changes to compliance demonstration requirements for regulated entities, offset and cost containment mechanisms. Most of the RGGI states have completed the regulatory and/or legislative processes required to amend existing state regulations to implement the RGGI program changes. However, as a result of the recent sales of several power plants located in these states, Dominion does not expect that RGGI will have a material effect on operations, financial condition, and/or cash flows.

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 set national emission standards for new coal, oil, integrated gasification, and combined cycle units larger than 25MW. The

proposed rule covered CO₂ only and does not apply to existing sources. The proposed rule also does not apply to any new or

existing biomass units. In June 2013, the President of the U.S. released a Climate Action Plan focusing on ways to meet the national GHG reduction goal of 17% from 2005 levels by 2020. Pursuant to the Presidential Memorandum issued in conjunction with the Climate Action Plan, the EPA withdrew the April 2012 proposal and re-proposed the NSPS standards for new sources on January 8, 2014 and is expected to finalize the rule in 2014 or early 2015. The Presidential Memorandum also directed the EPA to propose a rule for reconstructed, modified and existing sources of GHG emissions no later than June 2014, and issue a final rule no later than June 2015, to provide guidelines to the states to achieve the required GHG reductions. Dominion currently cannot predict with certainty the direct or indirect financial impact on operations from these rule revisions, but believes the expenditures to comply with any new requirements could be material.

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

In July 2011, the EPA signed a final rule deferring the need for Prevention of Significant Deterioration and Title V permitting for CO₂ emissions for biomass projects. This rule temporarily deferred for a period of up to 3 years the consideration of CO₂ emissions from biomass projects when determining whether a stationary source meets the Prevention of Significant Deterioration and Title V applicability thresholds, including those for the application of best available control technology.  In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however a mandate making this decision effective has not been issued.  Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the CO₂ deferral period.  It is unclear how the court's decision will affect biomass sources that were permitted during the deferral period, however the expenditures to comply with any new requirements could be material.

Natrium and Blue Racer

In January 2011, Dominion announced the development of a natural gas processing and fractionation facility in Natrium, West Virginia, and in July 2011 it executed a contract for the construction of the first phase of the facility. The first phase of the project is fully contracted and was placed into service in May 2013. In August 2013, the Natrium natural gas processing and fractionation facility was contributed to the Blue Racer joint venture. In September 2013, the Natrium facility was shut down following a fire at the plant. It returned to service in January 2014. There was no material impact on Dominion’s financial condition, results of operations, and/or cash flows.

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. Implementation of these enhancements is currently in progress. The information requests issued by the NRC request each reactor to reevaluate the seismic and flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. Dominion and Virginia Power do not currently expect that compliance with the NRC's March 2012 orders and information requests will materially impact their financial position, results of operations or cash flows during the approximately four-year implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion and Virginia Power are currently unable to estimate the potential financial impacts related to compliance with Tier 2 and Tier 3 recommendations.

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 2013 calculation for the NRC minimum financial assurance amount, aggregated for Dominion's and Virginia Power's nuclear units, excluding joint owners' assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.8 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 2013 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2013 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 NRC minimum financial assurance requirement, which may include, if needed, 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 $13.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

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

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

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

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

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

During 2013, Kewaunee ceased power production and commenced decommissioning activities.  Effective February 1, 2013, Kewaunee's accidental outage policy for replacement power costs was canceled.

ODEC, a part owner of North Anna, and Massachusetts Municipal and Green Mountain, 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.

In 2012, Dominion and Virginia Power resolved additional claims for damages incurred at Millstone, Kewaunee, Surry and North Anna with the Authorized Representative of the Attorney General. The Companies entered into settlement agreements that resolved claims for damages incurred through December 31, 2010, and also provide for periodic payments after that date for damages incurred through December 31, 2013. Initial settlement payments in the amounts of $20 million for Millstone, $6 million for Kewaunee and $75 million for Surry and North Anna were received in the fourth quarter of 2012. In the fourth quarter of 2013, Dominion received payment of approximately $5 million for resolution of claims incurred at Millstone for the period January 1, 2011 through June 30, 2012. The government has formally accepted an offer of settlement for resolution of claims incurred at Kewaunee in the amount of approximately $2 million for the period January 1, 2011 through December 31, 2012, and payment is expected in the first quarter of 2014. By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013.

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 $79 million and $36 million at December 31, 2013 and 2012, respectively. Virginia Power's receivables for spent nuclear fuel-related costs totaled $50 million and $26 million at December 31, 2013 and 2012, respectively.

Pursuant to a November 2013 decision of the U.S Court of Appeals for the District of Columbia Circuit, in January 2014 the Secretary of the DOE sent a recommendation to the U.S. Congress to adjust to zero the current fee of $1 per MWh for electricity paid by civilian nuclear power generators for disposal of spent nuclear fuel. The government continues to pursue further judicial review of the November 2013 decision and until such time as the processes specified in the Nuclear Waste Policy Act for adjustment of the fee are completed, civilian nuclear power generators, including the Companies, are required to pay the waste fee. In 2013, Dominion and Virginia Power recognized fees of $44 million and $27 million, respectively.

The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Long-Term Purchase Agreements

At December 31, 2013, 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:

	2014		2015		2016		2017		2018		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	336	$	316	$	253	$	159	$	104	$	163	$	1,331

(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, 2013, the present value of Virginia Power's total commitment for capacity payments is $1.1 billion. Capacity payments totaled $345 million, $337 million, and $338 million, and energy payments totaled $236 million, $214 million, and $275 million for 2013, 2012 and 2011, 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, 2013 are as follows:

	2014		2015		2016		2017		2018		Thereafter		Total
(millions)
Dominion	$	63	$	60	$	51	$	43	$	37	$	87	$	341
Virginia Power	$	27	$	26	$	21	$	17	$	14	$	27	$	132

Rental expense for Dominion totaled $101 million, $112 million, and $155 million for 2013, 2012 and 2011, respectively. Rental expense for Virginia Power totaled $42 million, $48 million, and $50 million for 2013, 2012, and 2011, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.

Guarantees, Surety Bonds and Letters of Credit

DOMINION

At December 31, 2013, Dominion had issued $69 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2013, Dominion's exposure under these guarantees was $39 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, 2013, Dominion's maximum remaining cumulative exposure under these equity funding agreements is $90 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, 2013, Dominion had issued the following subsidiary guarantees:

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	27	$	27
Commodity transactions(3)	3,158		403
Nuclear obligations(4)	232		68
Cove Point(5)	335		—
Other(6)	669		108
Total	$	4,421	$	606

(1) Represents the estimated portion of the guarantee's stated limit that is utilized as of December 31, 2013 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

(2) Guarantee of debt of a DEI subsidiary. In the event of default by the subsidiary, Dominion would be obligated to repay such amounts.

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

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

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

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

Additionally, as of December 31, 2013 Dominion had purchased $147 million of surety bonds and authorized the issuance of letters of credit by financial institutions of $11 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, 2013, Virginia Power had issued $14 million of guarantees primarily to support tax-exempt debt issued through conduits. Virginia Power had also purchased $59 million of surety bonds for various purposes, including providing workers' compensation coverage, and authorized the issuance of letters of credit by financial institutions of $1 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, 2013, 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.

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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, 2013		Dec. 31, 2012		Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	$ (83)	[1]	$ 131	[1]	$ 26	[1]
Commodity | Operating Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	(45)	[1]	168	[1]	111	[1]
Commodity | Purchased gas
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	(9)	[1]	(14)	[1]	(35)	[1]
Commodity | Electric fuel and other energy-related purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	(29)	[1]	(40)	[1]	(45)	[1]
Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	0	[1],[2]	17	[1],[2]	(5)	[1],[2]
Virginia Electric and Power Company
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	(16)	[3]	(50)	[3]	(50)	[3]
Virginia Electric and Power Company | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	(16)	[3],[4]	(50)	[3],[4]	(45)	[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]	$ 0	[3],[5]	$ (5)	[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.

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Shareholders' Equity (Schedule of Components of Accumulated Other Comprehensive Income) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	$ (877)
Other comprehensive income before reclassifications: gains (losses)	476
Amounts reclassified from accumulated other comprehensive income: (gains) losses	77	[1]
Total other comprehensive income income (loss)	553		(267)	(280)
Ending balance	(324)		(877)
Deferred gains and losses on derivatives-hedging activities
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(122)
Other comprehensive income before reclassifications: gains (losses)	(243)
Amounts reclassified from accumulated other comprehensive income: (gains) losses	77	[1]
Total other comprehensive income income (loss)	(166)
Ending balance	(288)
Unrealized gains and losses on investment securities
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	326
Other comprehensive income before reclassifications: gains (losses)	203
Amounts reclassified from accumulated other comprehensive income: (gains) losses	(55)	[1]
Total other comprehensive income income (loss)	148
Ending balance	474
Unrecognized pension and other postretirement benefit costs
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(1,081)
Other comprehensive income before reclassifications: gains (losses)	516
Amounts reclassified from accumulated other comprehensive income: (gains) losses	55	[1]
Total other comprehensive income income (loss)	571
Ending balance	(510)
Virginia Electric and Power Company
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	25
Other comprehensive income before reclassifications: gains (losses)	26
Amounts reclassified from accumulated other comprehensive income: (gains) losses	(3)	[1]
Total other comprehensive income income (loss)	23		6	(5)
Ending balance	48		25
Virginia Electric and Power Company | Deferred gains and losses on derivatives-hedging activities
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(6)
Other comprehensive income before reclassifications: gains (losses)	6
Amounts reclassified from accumulated other comprehensive income: (gains) losses	0	[1]
Total other comprehensive income income (loss)	6
Ending balance	0
Virginia Electric and Power Company | Unrealized gains and losses on investment securities
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	31
Other comprehensive income before reclassifications: gains (losses)	20
Amounts reclassified from accumulated other comprehensive income: (gains) losses	(3)	[1]
Total other comprehensive income income (loss)	17
Ending balance	$ 48

[1] See table below for details about these reclassifications.

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Operating Revenue (Tables)

12 Months Ended

Dec. 31, 2013

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,	2013		2012		2011
(millions)
Dominion
Electric sales:
Regulated	$	7,193	$	7,102	$	7,114
Nonregulated	2,511		2,483		2,721
Gas sales:
Regulated	323		250		287
Nonregulated	930		1,071		1,634
Gas transportation and storage	1,535		1,401		1,506
Other	628		528		503
Total operating revenue	$	13,120	$	12,835	$	13,765
Virginia Power
Regulated electric sales	$	7,193	$	7,102	$	7,114
Other	102		124		132
Total operating revenue	$	7,295	$	7,226	$	7,246

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Shareholders' Equity (Tables)

12 Months Ended

Dec. 31, 2013

Accumulated Other Comprehensive Income (Loss) [Line Items]

Accumulated other comprehensive income (loss)

Presented in the table below is a summary of AOCI by component:

At December 31,	2013			2012
(millions)
Dominion
Net deferred losses on derivatives-hedging activities, net of tax of $196 and $87	$	(288	)	$	(122	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(307) and $(206)	474			326
Net unrecognized pension and other postretirement benefit costs, net of tax of $365 and $745	(510		)	(1,081		)
Total AOCI	$	(324	)	$	(877	)
Virginia Power
Net deferred losses on derivatives-hedging activities, net of tax of $-- and $3	$	—		$	(6	)
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(30) and $(19)	48			31
Total AOCI	$	48		$	25

Schedule of Accumulated Other Comprehensive Income (Loss)

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

	Deferred gains and losses on derivatives-hedging activities			Unrealized gains and losses on investment securities			Unrecognized pension and other postretirement benefit costs			Total
(millions)
Year Ended December 31, 2013
Beginning balance	$	(122	)	$	326		$	(1,081	)	$	(877	)
Other comprehensive income before reclassifications: gains (losses)	(243		)	203			516			476
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)	77			(55		)	55			77
Net current period other comprehensive income (loss)	(166		)	148			571			553
Ending balance	$	(288	)	$	474		$	(510	)	$	(324	)

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

Reclassification out of Accumulated Other Comprehensive Income

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

Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Year Ended December 31, 2013
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	58		Operating revenue
	47			Purchased gas
	10			Electric fuel and other energy-related purchases
Interest rate contracts	15			Interest and related charges
Total	130
Tax	(53		)	Income tax expense
Total, net of tax	$	77
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(98	)	Other income
Impairment	8			Other income
Total	(90		)
Tax	35			Income tax expense
Total, net of tax	$	(55	)
Unrecognized pension and other postretirement benefit costs:
Prior-service costs (credits)	$	(8	)	Other operations and maintenance
Actuarial losses	102			Other operations and maintenance
Total	94
Tax	(39		)	Income tax expense
Total, net of tax	$	55

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 and 2011. There were no stock options outstanding in 2013. No options were granted under any plan in 2013, 2012 or 2011.

	Shares		Weighted - average Exercise Price		Weighted - average Remaining Contractual Life	Aggregated Intrinsic Value(1)
	(thousands)				(years)	(millions)
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, 2013, 2012 and 2011:

	Shares		Weighted - average Grant Date Fair Value
	(thousands)
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
Granted	312		54.70
Vested	(356	)	39.00
Cancelled and forfeited	(34	)	51.11
Nonvested at December 31, 2013	1,007		$	49.35

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, 2013, 2012 and 2011:

	Targeted Number of Shares		Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2010	161		$	31.79
Granted	3		43.54
Vested	(20	)	34.62
Cancelled and forfeited	(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
Granted	4		54.17
Vested	(2	)	43.54
Cancelled and forfeited	(1	)	43.54
Nonvested at December 31, 2013	5		$	53.85

Virginia Electric and Power Company

Accumulated Other Comprehensive Income (Loss) [Line Items]

Schedule of Accumulated Other Comprehensive Income (Loss)

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

	Deferred gains and losses on derivatives-hedging activities			Unrealized gains and losses on nuclear decommissioning trust funds			Total
(millions)
Year Ended December 31, 2013
Beginning balance	$	(6	)	$	31		$	25
Other comprehensive income before reclassifications: gains (losses)	6			20			26
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)	—			(3		)	(3		)
Net current period other comprehensive income (loss)	6			17			23
Ending balance	$	—		$	48		$	48

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

Reclassification out of Accumulated Other Comprehensive Income

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

Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Year Ended December 31, 2013
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(6	)	Other income
Impairment	1			Other income
Total	(5		)
Tax	2			Income tax expense
Total, net of tax	$	(3	)

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Fair Value Measurements (Fair Value, Option, Quantitative Disclosures) (Details) (USD $)																12 Months Ended																																										9 Months Ended		12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2013 Level 3	Dec. 31, 2013 Level 3 Gas Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Gas Physical and Financial Options:		Dec. 31, 2013 Level 3 FTRs Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Liquids Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Electricity Physical and Financial Forwards and Futures:	Dec. 31, 2013 Level 3 Electricity Full Requirements Contracts:	Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Minimum Gas Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Minimum Gas Physical and Financial Options:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Minimum FTRs Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Minimum Liquids Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Minimum Electricity Full Requirements Contracts:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Weighted Average Gas Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Weighted Average Gas Physical and Financial Options:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Weighted Average FTRs Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Weighted Average Liquids Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Weighted Average Electricity Full Requirements Contracts:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Maximum Gas Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Maximum Gas Physical and Financial Options:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Maximum FTRs Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Maximum Liquids Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Assets Maximum Electricity Full Requirements Contracts:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Minimum Gas Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Minimum Gas Physical and Financial Options:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Minimum FTRs Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Minimum Liquids Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Minimum Electricity Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Weighted Average Gas Physical and Financial Forwards and Futures:		Sep. 30, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Weighted Average Gas Physical and Financial Options:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Weighted Average Gas Physical and Financial Options:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Weighted Average FTRs Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Weighted Average Liquids Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Weighted Average Electricity Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Maximum Gas Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Maximum Gas Physical and Financial Options:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Maximum FTRs Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 Fair Value, Option, Quantitative Disclosures, Liabilities Maximum Liquids Physical and Financial Forwards and Futures:		Dec. 31, 2013 Level 3 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]
Derivative assets	$ 890,000,000	[1]	$ 828,000,000	[1]	$ 32,000,000	$ 14,000,000	[2]	$ 4,000,000	[2]	$ 2,000,000	[3]	$ 6,000,000	[4]		$ 6,000,000
Derivative liabilities	1,102,000,000	[5]	661,000,000	[5]	48,000,000	19,000,000	[2]	8,000,000	[2]	9,000,000	[3]	11,000,000	[4]	1,000,000
Market Price																(2)	[6]	3	[6]	(1)	[6]	1	[6]	10	[6]	2	[6]	4	[6]	0	[6]	1	[6]	42	[6],[7]	5	[6]	5	[6]	5	[6]	3	[6]	406	[6]	(2)	[6]	3	[6]	(1)	[6]	1	[6]	28	[6]	1	[6]			7	[6]	1	[6]	1	[6]	39	[6]	30	[6]	11	[6]	5	[6]	3	[6]	240	[6]
Price Volatility																		14.00%	[8]									20.00%	[8]									36.00%	[8]									14.00%	[8]											20.00%	[8]									36.00%	[8]
Price Correlation																		(9.00%)	[9]									36.00%	[9]									100.00%	[9]									(9.00%)	[9]											36.00%	[9]									100.00%	[9]
Mean Reversion																		$ 0.01	[10]									$ 1	[10]									$ 1	[10]									$ 0.01	[11]									$ 1	[11]											$ 1	[11]
Load Shaping																								0.00%	[12]									7.00%	[12]									10.00%	[12]
Usage Factor																								11.00%	[11]									16.00%	[11]									29.00%	[11]

[1] At December 31, 2013, the total derivative asset balance contains $687 million of current assets, which is presented in current derivative assets, in Dominion’s Consolidated Balance Sheet, and $203 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $518 million of current assets, which is presented in current derivative assets in Dominion’s Consolidated Balance Sheet and $310 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet.

[2] Includes basis.

[3] Information represents Virginia Power's quantitative information about Level 3 fair value measurements.

[4] Includes NGLs.

[5] At December 31, 2013, the total derivative liability balance contains $828 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet, and $274 million of noncurrent liabilities, which is presented in the other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $510 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet and $151 million of noncurrent liabilities, which is presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet.

[6] Represents market prices beyond defined terms for Levels 1 and 2.

[7] The range in market prices is the result of large variability in hourly power prices during peak and off-peak hours.

[8] Represents volatilities unrepresented in published markets.

[9] Represents intra-price correlations for which markets do not exist.

[10] Represents mean-reverting property in price simulation modeling.

[11] Represents expected increase (decrease) in sales volumes compared to historical usage.

[12] Converts block monthly loads to 24-hour load shapes.

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Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Operating Revenue	$ 13,120		$ 12,835	[1]	$ 13,765	[1]
Operating Expenses
Electric fuel and other energy-related purchases	3,885		3,645	[1]	3,942	[1]
Purchased electric capacity	358		387	[1]	454	[1]
Purchased gas	1,331		1,177	[1]	1,764	[1]
Other operations and maintenance	2,459		3,091	[1]	3,178	[1]
Depreciation, depletion and amortization	1,208		1,127	[1]	1,018	[1]
Other taxes	563		550	[1]	529	[1]
Total operating expenses	9,804		9,977	[1]	10,885	[1]
Income from operations	3,316		2,858	[1]	2,880	[1]
Other income	265		223	[1]	178	[1]
Interest and related charges	877		816	[1]	796	[1]
Income from continuing operations including noncontrolling interests before income taxes	2,704		2,265	[1]	2,262	[1]
Income tax expense	892	[2]	811	[1],[2]	778	[1],[2]
Income from continuing operations including noncontrolling interests	1,812		1,454	[1]	1,484	[1]
Income (loss) from discontinued operations	(92)		(1,125)	[1],[3]	(58)	[1],[3]
Net income including noncontrolling interests	1,720		329	[1]	1,426	[1]
Noncontrolling interests	23		27	[1]	18	[1]
Net income attributable to Dominion	1,697		302	[1]	1,408	[1]
Amounts attributable to Dominion:
Income from continuing operations, net of tax	1,789	[4]	1,427	[1],[4]	1,466	[1]
Loss from discontinued operations, net of tax	(92)		(1,125)	[1]	(58)	[1]
Net income attributable to Dominion	1,697		302	[1]	1,408	[1]
Earnings Per Common Share-Basic:
Income from continuing operations (in dollars per share)	$ 3.09	[4]	$ 2.49	[1],[4]	$ 2.56	[1]
Loss from discontinued operations (in dollars per share)	$ (0.16)	[4]	$ (1.96)	[1],[4]	$ (0.10)	[1]
Net income attributable to Dominion (in dollars per share)	$ 2.93		$ 0.53	[1]	$ 2.46	[1]
Earnings Per Common Share-Diluted:
Income from continuing operations (in dollars per share)	$ 3.09	[4]	$ 2.49	[1],[4]	$ 2.55	[1]
Loss from discontinued operations (in dollars per share)	$ (0.16)	[4]	$ (1.96)	[1],[4]	$ (0.10)	[1]
Net income attributable to Dominion (in dollars per share)	$ 2.93		$ 0.53	[1]	$ 2.45	[1]
Dividends declared per common share	$ 2.25		$ 2.11	[1]	$ 1.97	[1]
Virginia Electric and Power Company
Operating Revenue	7,295		7,226		7,246
Operating Expenses
Electric fuel and other energy-related purchases	2,304		2,368		2,506
Purchased electric capacity	358		386		452
Affiliated suppliers	290		305		306
Other	1,161		1,161		1,437
Depreciation, depletion and amortization	853		782		718
Other taxes	249		232		222
Total operating expenses	5,215		5,234		5,641
Income from operations	2,080		1,992		1,605
Other income	86		96		88
Interest and related charges	369		385		331
Income from continuing operations including noncontrolling interests before income taxes	1,797		1,703		1,362
Income tax expense	659	[5]	653	[5]	540	[5]
Net income attributable to Dominion	1,138		1,050		822
Amounts attributable to Dominion:
Net income attributable to Dominion	1,138		1,050		822
Preferred dividends	17		16		17
Balance available for common stock	$ 1,121		$ 1,034		$ 805

[1] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

[2] In 2012, Dominion’s current federal income tax expense for continuing and discontinued operations includes a $195 million benefit related to a carryback of its 2012 net operating loss. In 2011, Dominion’s deferred federal income tax expense includes the recognition of a $346 million benefit, including $51 million related to discontinued operations, for its 2011 net operating loss expected to be used to reduce taxable income in future years.

[3] Includes income tax benefit of $43 million, $692 million, and $33 million in 2013, 2012 and 2011, respectively. For 2012, includes impairment charges of $1.6 billion related to Brayton Point and Kincaid. See Note 6 for additional information.

[4] Amounts attributable to Dominion's common shareholders.

[5] In 2011, Virginia Power’s deferred federal income tax expense includes a $54 million benefit related to a portion of its 2011 net operating loss that is expected to be used in future years. Also, Virginia Power’s current federal income tax expense reflects the amounts of its 2011 net operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

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Investments (Tables)

12 Months Ended

Dec. 31, 2013

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)
2013
Marketable equity securities:
U.S.:
Large Cap	$	1,183	$	1,194	$	—			$	2,377
Other	49		23		—				72
Marketable debt securities:
Corporate debt instruments	332		16		(3		)		345
U.S. Treasury securities and agency debentures	589		8		(10		)		587
State and municipal	297		11		(5		)		303
Other	3		—		—				3
Cost method investments	106		—		—				106
Cash equivalents and other(2)	110		—		—				110
Total	$	2,669	$	1,252	$	(18	)	(3)	$	3,903
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

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

(2) Includes pending sales of securities of $11 million and pending purchases of securities of $6 million at December 31, 2013 and 2012, respectively.

(3) The fair value of securities in an unrealized loss position was $604 million and $195 million at December 31, 2013 and 2012, 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, 2013 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	128
Due after one year through five years	357
Due after five years through ten years	362
Due after ten years	391
Total	$	1,238

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,	2013		2012		2011
(millions)
Proceeds from sales	$	1,476	$	1,356	$	1,757
Realized gains(1)	157		98		79
Realized losses(1)	33		33		92

(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

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

Year Ended December 31,	2013			2012			2011
(millions)
Total other-than-temporary impairment losses(1)	$	31		$	26		$	75
Losses recorded to decommissioning trust regulatory liability	(13		)	(10		)	(24		)
Losses recognized in other comprehensive income (before taxes)	(10		)	(2		)	(3		)
Net impairment losses recognized in earnings	$	8		$	14		$	48

(1) Amounts include other-than-temporary impairment losses for debt securities of $18 million, $4 million and $6 million at December 31, 2013, 2012 and 2011, 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,			2013		2012
(millions)
Blue Racer Midstream LLC	50	%	$	510	$	39	Midstream gas and related services
Fowler I Holdings LLC	50	%	149		158		Wind-powered merchant generation facility
NedPower Mount Storm LLC	50	%	131		137		Wind-powered merchant generation facility
Iroquois Gas Transmission System, LP	24.72	%	105		102		Gas transmission system
Elwood Energy LLC(1)	—	%	—		117		Natural gas-fired merchant generation peaking facility
Other(2)	various		21		5
Total			$	916	$	558

(1) Following the 2013 sale of Elwood, at December 31, 2013, Dominion retained a 0.5% cost method investment. At December 31, 2012, Dominion owned 50% and Elwood was therefore considered an equity method investment.

(2) Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018.

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)
2013
Marketable equity securities:
U.S.:
Large Cap	$	506	$	514	$	—			$	1,020
Other	25		11		—				36
Marketable debt securities:
Corporate debt instruments	185		8		(2		)		191
U.S. Treasury securities and agency debentures	214		1		(3		)		212
State and municipal	163		4		(4		)		163
Cost method investments	106		—		—				106
Cash equivalents and other(2)	37		—		—				37
Total	$	1,236	$	538	$	(9	)	(3)	$	1,765
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

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

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

(3) The fair value of securities in an unrealized loss position was $299 million and $104 million at December 31, 2013 and 2012, respectively

Investments Classified by Contractual Maturity Date

The fair value of Virginia Power's debt securities at December 31, 2013, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	31
Due after one year through five years	163
Due after five years through ten years	196
Due after ten years	176
Total	$	566

Marketable Securities

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

Year Ended December 31,	2013		2012		2011
(millions)
Proceeds from sales	$	572	$	626	$	1,030
Realized gains(1)	52		42		34
Realized losses(1)	14		11		34

(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,	2013			2012			2011
(millions)
Total other-than-temporary impairment losses(1)	$	15		$	11		$	29
Losses recorded to decommissioning trust regulatory liability	(13		)	(10		)	(24		)
Losses recorded in other comprehensive income (before taxes)	(1		)	—			(1		)
Net impairment losses recognized in earnings	$	1		$	1		$	4

(1) Amounts include other-than-temporary impairment losses for debt securities of $9 million, $2 million and $4 million at December 31, 2013, 2012 and 2011, respectively

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Goodwill and Intangible Assets (Components of Intangible Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 870	$ 864
Accumulated Amortization	310	328
Virginia Electric and Power Company
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	271	303
Accumulated Amortization	78	122
Software, licenses and other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	867	859
Accumulated Amortization	308	327
Software, licenses and other | Virginia Electric and Power Company
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	271	303
Accumulated Amortization	78	122
Emissions allowances
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	3	5
Accumulated Amortization	$ 2	$ 1

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Commitments and Contingencies (Lease Commitments) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Loss Contingencies [Line Items]
Rental expense	$ 101	$ 112	$ 155
Virginia Electric and Power Company
Loss Contingencies [Line Items]
Rental expense	$ 42	$ 48	$ 50

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Shareholders' Equity (Accumulated Other Comprehensive Income (Loss)) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses on derivatives-hedging activities, net of tax	$ (288)	$ (122)
Net unrealized gains on nuclear decommissioning trust funds, net of tax	474	326
Net unrecognized pension and other postretirement benefit costs, net of tax	(510)	(1,081)
Total AOCI	(324)	(877)
Net unrealized gains on derivatives-hedging activities, tax	(196)	(87)
Net unrealized gains on nuclear decommissioning trust funds, tax	307	206
Net unrecognized pension and other postretirement benefit costs, tax	(365)	(745)
Virginia Electric and Power Company
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net unrealized losses on derivatives-hedging activities, net of tax	0	(6)
Net unrealized gains on nuclear decommissioning trust funds, net of tax	48	31
Total AOCI	48	25
Net unrealized gains on derivatives-hedging activities, tax	0	(3)
Net unrecognized pension and other postretirement benefit costs, tax	$ 30	$ 19

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Current Assets
Cash and cash equivalents	$ 316		$ 248
Customer receivables	1,695		1,621
Other receivables	141		96
Inventories:
Materials and supplies	689		684
Fossil fuel	393		467
Gas stored	94		108
Derivative assets	687		518
Margin Deposit Assets	620		212
Prepayments	192		326
Regulatory assets	217	[1]	203	[1]
Deferred income taxes	778		573
Other	335		287
Total current assets	5,940		5,140
Investments
Nuclear decommissioning trust funds	3,903		3,330
Investment in equity method affiliates	916		558
Other	283		303
Total investments	5,102		4,191
Property, Plant and Equipment
Property, plant and equipment	46,969		43,364
Property, plant and equipment, VIE	0		957
Accumulated depreciation, depletion and amortization	(14,341)		(13,548)
Total property, plant and equipment, net	32,628		30,773
Deferred Charges and Other Assets
Goodwill	3,086	[2]	3,130	[2]
Pension and other postretirement benefit assets	942		702
Intangible assets, net	560		536
Regulatory assets	1,228		1,717
Other	610		649
Total deferred charges and other assets	6,426		6,734
Total assets	50,096		46,838
Current Liabilities
Securities due within one year	1,519		1,363
Securities due within one year, VIE	0		860
Short-term debt	1,927		2,412
Accounts payable	1,168		1,137
Accrued interest, payroll and taxes	609		636
Derivative liabilities	828		510
Regulatory liabilities	128	[3]	136	[3]
Other	943		845
Total current liabilities	6,994		7,763
Long-Term Debt
Long-term debt	16,877		15,478
Junior subordinated notes	1,373		1,373
Remarketable Subordinated Notes, Noncurrent	1,080		0
Total long-term debt	19,330		16,851
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	7,114		5,800
Asset retirement obligations	1,484		1,641
Pension and other postretirement benefit liabilities	481		1,831
Regulatory liabilities	2,001		1,514
Other	793		556
Total deferred credits and other liabilities	11,873		11,342
Total liabilities	38,197		35,956
Subsidiary Preferred Stock Not Subject To Mandatory Redemption	257		257
Equity
Common stock-no par	5,783.0	[4]	5,493.0	[4]
Other paid-in capital	0		162
Retained earnings	6,183		5,790
Accumulated other comprehensive loss	(324)		(877)
Total common shareholders' equity	11,642		10,568
Noncontrolling interest	0		57
Total equity	11,642		10,625
Total liabilities and equity	50,096		46,838
Virginia Electric and Power Company
Current Assets
Cash and cash equivalents	16		28
Customer receivables	946		849
Other receivables	78		51
Inventories:
Materials and supplies	418		385
Fossil fuel	390		404
Prepayments	32		23
Regulatory assets	128		119
Deferred income taxes	87		92
Other	68		30
Total current assets	2,163		1,981
Investments
Nuclear decommissioning trust funds	1,765		1,515
Other	12		14
Total investments	1,777		1,529
Property, Plant and Equipment
Property, plant and equipment	32,848		30,631
Accumulated depreciation, depletion and amortization	(10,580)		(10,014)
Total property, plant and equipment, net	22,268		20,617
Deferred Charges and Other Assets
Intangible assets, net	193		181
Regulatory assets	417		396
Other	143		107
Total deferred charges and other assets	753		684
Total assets	26,961		24,811
Current Liabilities
Securities due within one year	58		418
Short-term debt	842		992
Accounts payable	479		430
Payables to affiliates	69		67
Affiliated current borrowings	97		435
Accrued interest, payroll and taxes	218		204
Derivative liabilities	12		33
Customer deposits	95		100
Regulatory liabilities	41		32
Other	306		296
Total current liabilities	2,217		3,007
Long-Term Debt
Total long-term debt	7,974		6,251
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	4,137		3,879
Asset retirement obligations	689		705
Regulatory liabilities	1,597		1,285
Other	292		194
Total deferred credits and other liabilities	6,715		6,063
Total liabilities	16,906		15,321
Subsidiary Preferred Stock Not Subject To Mandatory Redemption	257		257
Equity
Common stock-no par	5,738.0	[5]	5,738.0	[5]
Other paid-in capital	1,113		1,113
Retained earnings	2,899		2,357
Accumulated other comprehensive loss	48		25
Total common shareholders' equity	9,798		9,233
Total equity	9,798		9,233
Total liabilities and equity	$ 26,961		$ 24,811

[1] Current regulatory assets are presented in other current assets in Dominion's Consolidated Balance Sheets.

[2] Goodwill amounts do not contain any accumulated impairment losses.

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

[4] 1 billion shares authorized; 581 million shares and 576 million shares outstanding at December 31, 2013 and 2012, respectively.

[5] shares authorized at December 31, 2013 and 2012; 274,723 shares outstanding at December 31, 2013 and 2012.

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Goodwill and Intangible Assets (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Goodwill [Line Items]
Amortization expense for intangible assets	$ 72	$ 82	$ 78
Acquisition of intangible assets	81
Weighted-average amortization period (years)	10 years
Virginia Electric and Power Company
Goodwill [Line Items]
Amortization expense for intangible assets	22
Acquisition of intangible assets	$ 14
Weighted-average amortization period (years)	5 years

XML

Credit Risk (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Concentration Risk [Line Items]
Gross credit exposure	$ 263
Additional collateral to be posted if the credit-related contingent features were triggered	146	110
Collateral already posted	76	4
Fair value of all derivative instruments not fully collateralized	$ 169	$ 163
Investment Grade | Investment Grade Counterparties
Concentration Risk [Line Items]
Concentration of credit risk	63.00%
Investment Grade | CounterpartyA
Concentration Risk [Line Items]
Concentration of credit risk	6.00%

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Operating Segments (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended									12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting Information [Line Items]
Total operating expenses										$ 9,804		$ 9,977	[1]	$ 10,885	[1]
Income (loss) from discontinued operations										92		1,125	[1],[2]	58	[1],[2]
Impairment charge										1,600
Asset disposition adjustment										44		11
Loss from discontinued operations, net of tax										92		1,125	[1]	58	[1]
Income from operations	804	[3]	1,034	548	930	761	551	628	918	3,316		2,858	[1]	2,880	[1]
Corporate and Other
Segment Reporting Information [Line Items]
Total operating expenses										452		1,700		607
Net expenses attributable to other operating segments										184		1,500		364
Income (loss) from discontinued operations										92	[4]	1,125	[4]	58	[4]
Asset disposition adjustment										0	[5]	0	[5]
Dominion Generation
Segment Reporting Information [Line Items]
Income (loss) from discontinued operations										0	[4],[6]	0	[4],[6]	0	[4],[6]
Asset disposition adjustment										19	[7]	0
Net gain on investments										81
Net gain on investments after tax										49
Impairment charge														228
Asset impairment, net of tax														139
Income from operations														(66)
Operating income after tax														(39)
Impairment of emissions allowances														43
Impairment of emissions net of taxes														26
Dominion Generation | Brayton Point Kincaid And Elwood Power Stations
Segment Reporting Information [Line Items]
Loss before income taxes												1,700
Impairment charge						1,000
Loss from discontinued operations, net of tax												1,100
DVP
Segment Reporting Information [Line Items]
Income (loss) from discontinued operations										0	[6]	0	[6]	0	[6]
Asset disposition adjustment										0		0
Charge related to Biennial Review Order												87		96
Restoration costs net of tax												53		59
Dominion Energy
Segment Reporting Information [Line Items]
Income (loss) from discontinued operations										0		0		0
Asset disposition adjustment										25	[8]	11	[8]
Loss from operations										182
Loss from operations after tax										109
Impairment charge										55
Impairment charge after tax				33						33
Loss from producer services business										127
Loss from producer services business after tax				24						76
Brayton Point and Kincaid
Segment Reporting Information [Line Items]
Loss before income taxes				70
Brayton Point and Kincaid | Dominion Generation
Segment Reporting Information [Line Items]
Loss before income taxes										135				57
Income (loss) from discontinued operations										92
Amount of debt extinguishment										64
Amount of debt extinguishment after tax										38
Impairment charge										48
Long-lived assets impairment charges, net of tax										28
Loss from discontinued operation										17
Loss on discontinued operation, net of tax										18
Asset disposition adjustment										16
Loss from operations										6
Loss from operations after tax										8
Loss from discontinued operations, net of tax														33
Brayton Point and Kincaid | Dominion Energy
Segment Reporting Information [Line Items]
Loss from operations after tax				57
Kewaunee | Dominion Generation
Segment Reporting Information [Line Items]
Loss before income taxes												467
Loss from discontinued operations, net of tax												303
State Line and Salem Harbor | Dominion Generation
Segment Reporting Information [Line Items]
Loss before income taxes												49		34
Loss from discontinued operations, net of tax												22		25
Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Total operating expenses										5,215		5,234		5,641
Restoration costs net of tax	28
Asset impairment, net of tax								42
Income from operations	408		679	463	530	417	746	361	468	2,080		1,992		1,605
Virginia Electric and Power Company | Corporate and Other
Segment Reporting Information [Line Items]
Total operating expenses										47		51		268
Virginia Electric and Power Company | Dominion Generation
Segment Reporting Information [Line Items]
Charge related to Biennial Review Order										40
Restoration costs net of tax										28
Impairment charge														228
Impairment charge, net of tax														139
Impairment of emissions allowances														43
Impairment of emissions net of taxes														26
Virginia Electric and Power Company | DVP
Segment Reporting Information [Line Items]
Charge related to Biennial Review Order												87		96
Restoration costs net of tax												$ 53		$ 59

[1] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

[2] Includes income tax benefit of $43 million, $692 million, and $33 million in 2013, 2012 and 2011, respectively. For 2012, includes impairment charges of $1.6 billion related to Brayton Point and Kincaid. See Note 6 for additional information.

[3] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3.

[4] Segment information for 2012 and 2011 has been recast to reflect Brayton Point and Kincaid as discontinued operations, as discussed in Note 3.

[5] Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.

[6] Amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

[7] See Note 3 for a discussion of Dominion's dispositions and related goodwill write-offs.

[8] Related to assets sold or contributed to Blue Racer.

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Significant Accounting Policies (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policy [Line Items]
Accrued unbilled revenue	$ 555	$ 411
Percentage of fuel currently subject to deferred fuel accounting	84.00%
Interest income	3		12
Reduction in interest expense	10	3	7
Income Tax Interest Income		8
Reduction in penalties (less than $1 million)		1	1
Accrued interest receivable	5	5
Interest and penalties payable	15	10
Income tax examination, penalties accrued	1	1
Accounts payable for checks outstanding	38	53
Margin assets	620	212
Margin liabilities	2	4
Capitalized interest costs	66	91	85
Inventory under LIFO method	7	24
Amount exceeded on LIFO basis	77	69
Virginia Electric and Power Company
Accounting Policy [Line Items]
Accrued unbilled revenue	395	348
Income Tax Interest Income			12
Income taxes payable	22
Noncurrent federal and state income taxes payable	28	36
Accounts payable for checks outstanding	21	30
Margin assets	11	18
Capitalized interest costs	33	31	31
AFUDC related to projects	32	37	20
State | Virginia Electric and Power Company
Accounting Policy [Line Items]
Income tax receivable	3
Non current income tax receivable	12
Federal | Virginia Electric and Power Company
Accounting Policy [Line Items]
Prepaid federal and state income taxes		$ 10

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Regulatory Assets and Liabilities (Regulatory Assets and Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Regulatory Assets And Liabilities [Line Items]
Deferred rate adjustment clause costs	$ 89	[1]	$ 55	[1]
Unrecovered gas costs	50	[2]	59	[2]
Virginia sales taxes	46	[3]	37	[3]
Derivatives	16	[4]	0	[4]
Plant retirement	1	[5]	25	[5]
Other	15		27
Regulatory assets-current	217	[6]	203	[6]
Unrecognized pension and other postretirement benefit costs	706	[7]	1,210	[7]
Deferred rate adjustment clause costs	287	[1]	173	[1]
Income taxes recoverable through future rates	155	[8]	140	[8]
Derivatives	16	[4]	105	[4]
Other postretirement benefit costs	12	[9]	21	[9]
Plant retirement	10	[5]	11	[5]
Other	42		57
Regulatory assets-non-current	1,228		1,717
Total regulatory assets	1,445		1,920
PIPP, regulatory liabilities-current	76	[10]	100	[10]
Deferred cost of fuel used in electric generation	24	[11]	7	[11]
Other	28		29
Regulatory liabilities-current	128	[12]	136	[12]
Provision for future cost of removal and AROs	1,028		985
Decommissioning trust	693		501
Unrecognized pension and other postretirement benefit costs	174	[7]	2	[7]
Deferred cost of fuel used in electric generation	90	[11]	13	[11]
Other	16		13
Regulatory liabilities-non-current	2,001		1,514
Total regulatory liabilities	2,129		1,650
Virginia Electric and Power Company
Regulatory Assets And Liabilities [Line Items]
Deferred rate adjustment clause costs	62	[1]	51	[1]
Virginia sales taxes	46	[3]	37	[3]
Derivatives	16	[4]	0	[4]
Plant retirement	1	[5]	25	[5]
Other	3		6
Regulatory assets-current	128		119
Deferred rate adjustment clause costs	227	[1]	127	[1]
Income taxes recoverable through future rates	124	[8]	110	[8]
Derivatives	16	[4]	105	[4]
Plant retirement	10	[5]	11	[5]
Other	40		43
Regulatory assets-non-current	417		396
Total regulatory assets	545		515
Deferred cost of fuel used in electric generation	24	[11]	7	[11]
Other	17		25
Regulatory liabilities-current	41		32
Provision for future cost of removal	807	[13]	763	[13]
Decommissioning trust	693	[14]	501	[14]
Deferred cost of fuel used in electric generation	90	[11]	14	[11]
Other	7		7
Regulatory liabilities-non-current	1,597		1,285
Total regulatory liabilities	$ 1,638		$ 1,317

[1] Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for more information.

[2] Reflects unrecovered gas costs at Dominion's regulated gas operations, which are recovered through annual filings with the applicable regulatory authority.

[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] 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 costs anticipated to be recovered in North Carolina base rates for certain coal units expected to be retired.

[6] Current regulatory assets are presented in other current assets in Dominion's Consolidated Balance Sheets.

[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] Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power's generation operations. For 2013, amount includes approximately $5 million related to DOE claims. See Note 13 for more information.

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

[13] 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.

[14] 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.

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Operating Segments

12 Months Ended

Dec. 31, 2013

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
Dominion Generation	Regulated electric fleet	X	X
	Merchant electric fleet	X
	Nonregulated retail energy marketing (electric and gas)(1)	X
Dominion Energy	Gas transmission and storage	X
	Gas distribution and storage	X
	LNG services	X
	Producer services	X

(1) As a result of Dominion's decision to realign its business units effective for 2013 year-end reporting, nonregulated retail energy marketing operations were moved from DVP to the Dominion Generation segment.

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 operations that are 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.

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

DOMINION

In 2013, Dominion reported after-tax net expense of $452 million in the Corporate and Other segment, with $184 million of these net expenses attributable to specific items related to its operating segments.

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

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

• A $182 million ($109 million after-tax) net loss, including a $55 million ($33 million after-tax) impairment charge related to certain natural gas infrastructure assets and a $127 million ($76 million after-tax) loss related to the producer services business discussed above, attributable to Dominion Energy; partially offset by

• An $81 million ($49 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.

In 2012, Dominion reported after-tax net expense of $1.7 billion in the Corporate and Other segment, with $1.5 billion of these net expenses attributable to specific items related 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 discontinued operations, including impairment charges, of Brayton Point and Kincaid, which were sold in 2013, attributable to Dominion Generation;

• 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 $607 million for specific items in the Corporate and Other segment, with $364 million of these net expenses attributable to specific items related 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 ($33 million after-tax) net loss from discontinued operations of Brayton Point and Kincaid, which were sold in 2013, attributable to Dominion Generation;

• 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; 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.

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

Year Ended December 31,	DVP(1)		Dominion Generation(1)(2)			Dominion Energy		Corporate and Other(2)			Adjustments & Eliminations(1)			Consolidated Total
(millions)
2013
Total revenue from external customers	$	1,825	$	8,445		$	1,783	$	3		$	1,064		$	13,120
Intersegment revenue	9		68			1,063		609			(1,749		)	—
Total operating revenue	1,834		8,513			2,846		612			(685		)	13,120
Depreciation, depletion and amortization	427		518			228		35			—			1,208
Equity in earnings of equity method investees	—		(14		)	21		7			—			14
Interest income	—		66			12		42			(66		)	54
Interest and related charges	175		220			26		522			(66		)	877
Income taxes	287		483			409		(287		)	—			892
Loss from discontinued operations, net of tax	—		—			—		(92		)	—			(92		)
Net income (loss) attributable to Dominion	475		1,031			643		(452		)	—			1,697
Investment in equity method investees	—		280			615		21			—			916
Capital expenditures	1,361		1,605			1,043		95			—			4,104
Total assets (billions)	11.9		22.0			12.1		8.5			(4.4		)	50.1
2012
Total revenue from external customers	$	1,846	$	8,170		$	1,813	$	155		$	851		$	12,835
Intersegment revenue	9		104			930		608			(1,651		)	—
Total operating revenue	1,855		8,274			2,743		763			(800		)	12,835
Depreciation, depletion and amortization	392		483			216		36			—			1,127
Equity in earnings of equity method investees	—		3			23		(1		)	—			25
Interest income	1		65			30		71			(106		)	61
Interest and related charges	187		177			47		511			(106		)	816
Income taxes	278		576			352		(395		)	—			811
Loss from discontinued operations, net of tax	—		—			—		(1,125		)	—			(1,125		)
Net income (loss) attributable to Dominion	439		1,021			551		(1,709		)	—			302
Investment in equity method investees	—		414			141		3			—			558
Capital expenditures	1,158		1,615			1,350		22			—			4,145
Total assets (billions)	11.5		21.8			11.2		12.6			(10.3		)	46.8
2011
Total revenue from external customers	$	1,791	$	8,759		$	2,044	$	56		$	1,115		$	13,765
Intersegment revenue	63		123			1,077		595			(1,858		)	—
Total operating revenue	1,854		8,882			3,121		651			(743		)	13,765
Depreciation, depletion and amortization	369		413			207		29			—			1,018
Equity in earnings of equity method investees	—		3			23		9			—			35
Interest income	10		65			27		71			(106		)	67
Interest and related charges	183		148			57		514			(106		)	796
Income taxes	264		655			323		(464		)	—			778
Loss from discontinued operations, net of tax	—		—			—		(58		)	—			(58		)
Net income (loss) attributable to Dominion	416		1,078			521		(607		)	—			1,408
Capital expenditures	1,091		1,593			907		61			—			3,652

(1) Amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

(2) Segment information for 2012 and 2011 has been recast to reflect Brayton Point and Kincaid as discontinued operations, as discussed in Note 3.

At December 31, 2013, 2012, and 2011, 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 2013, Virginia Power reported after-tax net expenses of $47 million for specific items attributable to its operating segments in the Corporate and Other segment.

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

• A $40 million ($28 million after-tax) charge in connection with the 2013 Biennial Review Order, attributable to Dominion Generation.

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 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.

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)
2013
Operating revenue	$	1,826	$	5,475	$	(6	)	$	—		$	7,295
Depreciation and amortization	427		425		1			—			853
Interest income	—		6		—			—			6
Interest and related charges	175		192		2			—			369
Income taxes	286		399		(26		)	—			659
Net income (loss)	483		702		(47		)	—			1,138
Capital expenditures	1,360		1,173		—			—			2,533
Total assets (billions)	12.0		15.1		—			(0.1		)	27.0
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

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Commitments and Contingencies (Nuclear Operations) (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended				3 Months Ended				12 Months Ended					3 Months Ended
	Nov. 30, 2013	Dec. 31, 2013	Dec. 31, 2013 Spent Nuclear Fuel	Dec. 31, 2012 Spent Nuclear Fuel	Dec. 31, 2013 Millstone Unit 1	Dec. 31, 2013 Kewaunee	Dec. 31, 2012 Kewaunee	Dec. 31, 2013 Millstone	Dec. 31, 2012 Millstone	Dec. 31, 2013 Nuclear Plant	Dec. 31, 2013 Virginia Electric and Power Company	Dec. 31, 2013 Virginia Electric and Power Company Spent Nuclear Fuel	Dec. 31, 2012 Virginia Electric and Power Company Spent Nuclear Fuel	Dec. 31, 2013 Virginia Electric and Power Company Kewaunee	Dec. 31, 2012 Virginia Electric and Power Company Surry and North Anna
Loss Contingencies [Line Items]
Coverage that exceeds NRC minimum requirement		$ 1,060,000,000.00
Minimum financial assurance					2,800,000,000									1,800,000,000
Liability protection under Price-Anderson Act										13,600,000,000
Amount of coverage purchased from commercial insurance pools		375,000,000
Amount that could be assessed for each licensed reactor		127,000,000
Amount that could be assessed for each licensed reactor per reactor		19,000,000
Maximum assessment for premiums on insurance policy		71,000,000									39,000,000
Maximum assessment for insurance policy		19,000,000									9,000,000
Payments for legal settlements							6,000,000	5,000,000	20,000,000						75,000,000
Litigation Settlement, Amount						2,000,000
Receivables			79,000,000	36,000,000								50,000,000	26,000,000
Current fee per kWh for electricity paid by civilian nuclear power generators	1
Waste fee recognized		$ 44,000,000									$ 27,000,000

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Income Taxes (Income Tax Expense for Continuing Operations Including Noncontrolling Interests) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Current:
Federal	$ 317	[1]	$ 43	[1]	$ 31	[1]
State	110	[1]	84	[1]	16	[1]
Total current expense	427	[1]	127	[1]	47	[1]
Deferred:
Federal	497	[1]	645	[1]	685	[1]
State	(31)	[1]	40	[1]	48	[1]
Total deferred expense	466	[1]	685	[1]	733	[1]
Amortization of deferred investment tax credits	(1)	[1]	(1)	[1]	(2)	[1]
Total income tax expense	892	[1]	811	[1],[2]	778	[1],[2]
Operating loss carryforward			195		51
Tax benefit recognized					346
Virginia Electric and Power Company
Current:
Federal	357	[3]	70	[3]	(35)	[3]
State	62	[3]	81	[3]	79	[3]
Total current expense	419	[3]	151	[3]	44	[3]
Deferred:
Federal	224	[3]	482	[3]	484	[3]
State	17	[3]	21	[3]	13	[3]
Total deferred expense	241	[3]	503	[3]	497	[3]
Amortization of deferred investment tax credits	(1)	[3]	(1)	[3]	(1)	[3]
Total income tax expense	659	[3]	653	[3]	540	[3]
Tax benefit recognized					$ 54

[1] In 2012, Dominion’s current federal income tax expense for continuing and discontinued operations includes a $195 million benefit related to a carryback of its 2012 net operating loss. In 2011, Dominion’s deferred federal income tax expense includes the recognition of a $346 million benefit, including $51 million related to discontinued operations, for its 2011 net operating loss expected to be used to reduce taxable income in future years.

[2] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

[3] In 2011, Virginia Power’s deferred federal income tax expense includes a $54 million benefit related to a portion of its 2011 net operating loss that is expected to be used in future years. Also, Virginia Power’s current federal income tax expense reflects the amounts of its 2011 net operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETSAND LIABILITIES

Regulatory assets and liabilities include the following:

At December 31,	2013		2012
(millions)
Dominion
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	89	$	55
Unrecovered gas costs(2)	50		59
Virginia sales taxes(3)	46		37
Derivatives(4)	16		—
Plant retirement(5)	1		25
Other	15		27
Regulatory assets-current(6)	217		203
Unrecognized pension and other postretirement benefit costs(7)	706		1,210
Deferred rate adjustment clause costs(1)	287		173
Income taxes recoverable through future rates(8)	155		140
Derivatives(4)	16		105
Other postretirement benefit costs(9)	12		21
Plant retirement(5)	10		11
Other	42		57
Regulatory assets-non-current	1,228		1,717
Total regulatory assets	$	1,445	$	1,920
Regulatory liabilities:
PIPP(10)	$	76	$	100
Deferred cost of fuel used in electric generation(11)	24		7
Other	28		29
Regulatory liabilities-current(12)	128		136
Provision for future cost of removal and AROs(13)	1,028		985
Decommissioning trust(14)	693		501
Unrecognized pension and other postretirement benefit costs(7)	174		2
Deferred cost of fuel used in electric generation(11)	90		13
Other	16		13
Regulatory liabilities-non-current	2,001		1,514
Total regulatory liabilities	$	2,129	$	1,650
Virginia Power
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	62	$	51
Virginia sales taxes(3)	46		37
Derivatives(4)	16		—
Plant retirement(5)	1		25
Other	3		6
Regulatory assets-current	128		119
Deferred rate adjustment clause costs(1)	227		127
Income taxes recoverable through future rates(8)	124		110
Derivatives(4)	16		105
Plant retirement(5)	10		11
Other	40		43
Regulatory assets-non-current	417		396
Total regulatory assets	$	545	$	515
Regulatory liabilities:
Deferred cost of fuel used in electric generation(11)	$	24	$	7
Other	17		25
Regulatory liabilities-current	41		32
Provision for future cost of removal(13)	807		763
Decommissioning trust(14)	693		501

Deferred cost of fuel used in electric generation(11)	90		14
Other	7		7
Regulatory liabilities-non-current	1,597		1,285
Total regulatory liabilities	$	1,638	$	1,317

(1) Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects. See Note 13 for more information.

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

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

(6) Current regulatory assets are presented in other current assets in Dominion's Consolidated Balance Sheets.

(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) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power's generation operations. For 2013, amount includes approximately $5 million related to DOE claims. See Note 13 for more information.

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

(13) 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.

(14) 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, 2013, approximately $129 million of Dominion's and $63 million of Virginia Power's regulatory assets represented past expenditures on which they do not currently earn a return. The majority of these expenditures are expected to be recovered within the next two years.

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Quarterly Financial and Common Stock Data (Unaudited)

12 Months Ended

Dec. 31, 2013

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, 2013 and 2012 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			Second Quarter			Third Quarter			Fourth Quarter (2)			Full Year
(millions, except per share amounts)
2013
Operating revenue	$	3,523		$	2,980		$	3,432		$	3,185		$	13,120
Income from operations	930			548			1,034			804			3,316
Net income including noncontrolling interests	502			208			575			435			1,720
Income from continuing operations(1)	494			272			592			431			1,789
Income (loss) from discontinued operations(1)	1			(70		)	(23		)	—			(92		)
Net income attributable to Dominion	495			202			569			431			1,697
Basic EPS:
Income from continuing operations(1)	0.86			0.47			1.02			0.74			3.09
Income (loss) from discontinued operations(1)	—			(0.12		)	(0.04		)	—			(0.16		)
Net income attributable to Dominion	0.86			0.35			0.98			0.74			2.93
Diluted EPS:
Income from continuing operations(1)	0.86			0.47			1.02			0.74			3.09
Income (loss) from discontinued operations(1)	—			(0.12		)	(0.04		)	—			(0.16		)
Net income attributable to Dominion	0.86			0.35			0.98			0.74			2.93
Dividends declared per share	0.5625			0.5625			0.5625			0.5625			2.25
Common stock prices (intraday high-low)	$58.25  - 51.92			$61.85  - 53.79			$64.04 - 55.51			$67.97  - 61.36			$67.97  - 51.92
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Full Year
2012
Operating revenue	$	3,397		$	3,005		$	3,332		$	3,101		$	12,835
Income from operations	918			628			551			761			2,858
Net income (loss) including noncontrolling interests	501			265			215			(652		)	329
Income from continuing operations(1)	504			290			261			372			1,427
Income (loss) from discontinued operations(1)	(10		)	(32		)	(52		)	(1,031		)	(1,125		)
Net income attributable to Dominion	494			258			209			(659		)	302
Basic EPS:
Income from continuing operations(1)	0.88			0.51			0.45			0.65			2.49
Loss from discontinued operations(1)	(0.02		)	(0.06		)	(0.09		)	(1.80		)	(1.96		)
Net income (loss) attributable to Dominion	0.86			0.45			0.36			(1.15		)	0.53
Diluted EPS:
Income from continuing operations(1)	0.88			0.51			0.45			0.64			2.49
Loss from discontinued operations(1)	(0.02		)	(0.06		)	(0.09		)	(1.79		)	(1.96		)
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

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

(2) Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3.

Dominion's 2013 results include the impact of the following significant items:

• Second quarter results include a $70 million after-tax net loss from discontinued operations of Brayton Point and Kincaid; and a $57 million after-tax net loss, including a $33 million after-tax impairment charge related to certain natural gas infrastructure assets and a $24 million after-tax loss related to the producer services business.

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.

VIRGINIA POWER

Virginia Power's quarterly results of operations were as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
(millions)
2013
Operating revenue	$	1,781	$	1,710	$	2,059	$	1,745	$	7,295
Income from operations	530		463		679		408		2,080
Net income	287		265		387		199		1,138
Balance available for common stock	283		261		383		194		1,121
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

Virginia Power's 2013 results include the impact of the following significant item:

• Fourth quarter results include a $28 million after-tax charge resulting from impacts of the 2013 Biennial Review Order.

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.

XML

Regulatory Assets and Liabilities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets And Liabilities [Line Items]
Regulatory assets represented past expenditures not earning return	$ 129
Period expenditures expected to be recovered (years)	2 years
DOE Claims	2,129	1,650
Virginia Electric and Power Company
Regulatory Assets And Liabilities [Line Items]
Regulatory assets represented past expenditures not earning return	63
DOE Claims	1,638	1,317
DOE Claims
Regulatory Assets And Liabilities [Line Items]
DOE Claims	$ 5

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Employee Benefit Plans (Fair values of pension and post retirement plan assets by asset category) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	$ 6,113	$ 5,553
Pension Benefits | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	179	195
Pension Benefits | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1,220	1,031
Pension Benefits | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	514	524
Pension Benefits | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	308	381
Pension Benefits | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	391	395
Pension Benefits | Common/collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1,387	0
Pension Benefits | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	494	1,053
Pension Benefits | Fixed Income: | U.S. Treasury securities and agency debentures
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	231	635
Pension Benefits | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	176	72
Pension Benefits | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	57	48
Pension Benefits | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	32	29
Pension Benefits | Real estate: | Partnerships
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	227	321
Pension Benefits | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	530	456
Pension Benefits | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	180	192
Pension Benefits | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	187	221
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	2,639	2,286
Pension Benefits | Level 1 | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	53	0
Pension Benefits | Level 1 | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1,220	927
Pension Benefits | Level 1 | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	514	425
Pension Benefits | Level 1 | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	308	313
Pension Benefits | Level 1 | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	391	228
Pension Benefits | Level 1 | Common/collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Pension Benefits | Level 1 | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	43	27
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	2	331
Pension Benefits | Level 1 | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	69	1
Pension Benefits | Level 1 | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	7	5
Pension Benefits | Level 1 | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	32	29
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	2,350	2,077
Pension Benefits | Level 2 | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	126	195
Pension Benefits | Level 2 | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	104
Pension Benefits | Level 2 | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	99
Pension Benefits | Level 2 | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	68
Pension Benefits | Level 2 | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	167
Pension Benefits | Level 2 | Common/collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1,387	0
Pension Benefits | Level 2 | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	451	1,026
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	229	304
Pension Benefits | Level 2 | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	107	71
Pension Benefits | Level 2 | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	50	43
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	1,124	1,190
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 | Common/collective trust funds
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	227	321
Pension Benefits | Level 3 | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	530	456
Pension Benefits | Level 3 | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	180	192
Pension Benefits | Level 3 | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	187	221
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	1,315	1,156
Other Postretirement Plans | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	17	13
Other Postretirement Plans | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	472	383
Other Postretirement Plans | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	26	66
Other Postretirement Plans | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	111	96
Other Postretirement Plans | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	20	19
Other Postretirement Plans | Common/collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	502	0
Other Postretirement Plans | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	25	161
Other Postretirement Plans | Fixed Income: | U.S. Treasury securities and agency debentures
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	12	282
Other Postretirement Plans | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	9	9
Other Postretirement Plans | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	3	2
Other Postretirement Plans | Real estate: | REITs
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	2	1
Other Postretirement Plans | Real estate: | Partnerships
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	19	24
Other Postretirement Plans | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	60	58
Other Postretirement Plans | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	27	31
Other Postretirement Plans | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	10	11
Other Postretirement Plans | Level 1
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	640	521
Other Postretirement Plans | Level 1 | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	3	0
Other Postretirement Plans | Level 1 | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	472	378
Other Postretirement Plans | Level 1 | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	26	21
Other Postretirement Plans | Level 1 | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	111	93
Other Postretirement Plans | Level 1 | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	20	11
Other Postretirement Plans | Level 1 | Common/collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	0
Other Postretirement Plans | Level 1 | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	2	1
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	0	16
Other Postretirement Plans | Level 1 | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	4	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	2	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	559	511
Other Postretirement Plans | Level 2 | Cash equivalents and other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	14	13
Other Postretirement Plans | Level 2 | U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	5
Other Postretirement Plans | Level 2 | U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	45
Other Postretirement Plans | Level 2 | Non-U.S. equity: | Large Cap
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	3
Other Postretirement Plans | Level 2 | Non-U.S. equity: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	0	8
Other Postretirement Plans | Level 2 | Common/collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	502	0
Other Postretirement Plans | Level 2 | Fixed Income: | Corporate debt instruments
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	23	160
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	12	266
Other Postretirement Plans | Level 2 | Fixed Income: | State and municipal
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	5	9
Other Postretirement Plans | Level 2 | Fixed Income: | Other
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	3	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	116	124
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 | Common/collective trust funds
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	19	24
Other Postretirement Plans | Level 3 | Other alternative investments: | Private equity
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	60	58
Other Postretirement Plans | Level 3 | Other alternative investments: | Debt
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	27	31
Other Postretirement Plans | Level 3 | Other alternative investments: | Hedge funds
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets by asset category	$ 10	$ 11

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

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 2012 and 2013 were as follows:

	Amount
(millions)
Dominion
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(2)	242
Accretion	77
Other	(23		)
AROs at December 31, 2012(1)	$	1,705
Obligations incurred during the period	13
Obligations settled during the period	(68		)
Revisions in estimated cash flows(3)	(129		)
Accretion	86
Other	(29		)
AROs at December 31, 2013(1)	$	1,578
Virginia Power
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
Obligations incurred during the period	2
Obligations settled during the period	(2		)
Revisions in estimated cash flows(3)	(52		)
Accretion	38
Other	(2		)
AROs at December 31, 2013	$	689

(1) Includes $15 million, $64 million and $94 million reported in other current liabilities at December 31, 2011, 2012, and 2013, respectively.

(2) Primarily reflects the accelerated timing of the decommissioning of Kewaunee that began in 2013.

(3) Primarily reflects lower anticipated nuclear decommissioning costs.

(4) Includes $1 million reported in other current liabilities.

(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, 2013 and 2012, the aggregate fair value of Dominion's trusts, consisting primarily of equity and debt securities, totaled $3.9 billion and $3.3 billion, respectively. At December 31, 2013 and 2012, the aggregate fair value of Virginia Power's trusts, consisting primarily of debt and equity securities, totaled $1.8 billion and $1.5 billion, respectively.

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Income Taxes (Unrecognized Tax Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1	$ 293	$ 347	$ 307
Increases-prior period positions	17	28	127
Decreases-prior period positions	(99)	(106)	(119)
Increases-current period positions	30	43	64
Decreases-current period positions	(5)	0	(21)
Settlements with tax authorities	(2)	(4)	0
Expiration of statutes of limitations	(12)	(15)	(11)
Balance at December 31	222	293	347
Virginia Electric and Power Company
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1	57	114	117
Increases-prior period positions	12	4	22
Decreases-prior period positions	(42)	(80)	(51)
Increases-current period positions	14	24	47
Decreases-current period positions	0	0	(21)
Settlements with tax authorities	(2)	(4)	0
Expiration of statutes of limitations	0	(1)	0
Balance at December 31	$ 39	$ 57	$ 114

XML

Long-Term Debt (Trust Preferred Securities and Junior Subordinated Notes Outstanding) (Details) (USD $) Share data in Thousands, unless otherwise specified					12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2013 January 2001 Dominion Resources Capital Trust III	Dec. 31, 2013 8.4% Debentures due 1/15/2031
Debt Instrument [Line Items]
Date Established					January 2001
Units					10
Rate					8.40%
Capital Securities Amount					$ 10,000,000
Common Securities Amount	5,783,000,000	[1]	5,493,000,000	[1]	300,000
Junior subordinated notes						$ 10,000,000
RSN Annual Interest Rate						8.40%
Debt instrument maturity date						Jan. 15, 2031

[1] 1 billion shares authorized; 581 million shares and 576 million shares outstanding at December 31, 2013 and 2012, respectively.

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Allowance - Customer Receivables	$ 25	$ 28
Allowance - Other	4	4
Common Stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares outstanding	581,000,000	576,000,000
Virginia Electric and Power Company
Allowance - Customer Receivables	11	10
Allowance - Other	$ 2	$ 3
Common Stock, shares authorized	500,000	500,000
Common stock, shares outstanding	274,723	274,723

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Consolidated Statements of Income (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
EPS impact of recast Brayton Point and Kincaid discontinued operations	$ 1.92	$ 0.06
Discontinued operation tax expense	$ 692,000,000	$ 33,000,000

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Derivatives and Hedge Accounting Activities

12 Months Ended

Dec. 31, 2013

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.

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

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

DOMINION

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

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	137	$	—	$	137	$	93	$	—	$	93
Commodity contracts:
Over-the-counter	240		—		240		290		—		290
Exchange	506		—		506		416		—		416
Total derivatives, subject to a master netting or similar arrangement	883		—		883		799		—		799
Total derivatives, not subject to a master netting or similar arrangement	7		—		7		29		—		29
Total(1)	$	890	$	—	$	890	$	828	$	—	$	828

(1) At December 31, 2013, the total derivative asset balance contains $687 million of current assets, which is presented in current derivative assets, in Dominion’s Consolidated Balance Sheet, and $203 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $518 million of current assets, which is presented in current derivative assets in Dominion’s Consolidated Balance Sheet and $310 million of noncurrent assets, which is presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet.

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	137	$	—	$	—	$	137	$	93	$	19	$	—	$	74
Commodity contracts:
Over-the-counter	240		63		—		177		290		97		—		193
Exchange	506		505		—		1		416		350		4		62
Total	$	883	$	568	$	—	$	315	$	799	$	466	$	4	$	329

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	66	$	—	$	66
Commodity contracts:
Over-the-counter	262		—		262		191		—		191
Exchange	838		—		838		393		—		393
Total derivatives, subject to a master netting or similar arrangement	1,100		—		1,100		650		—		650
Total derivatives, not subject to a master netting or similar arrangement	2		—		2		11		—		11
Total(1)	$	1,102	$	—	$	1,102	$	661	$	—	$	661

(1) At December 31, 2013, the total derivative liability balance contains $828 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet, and $274 million of noncurrent liabilities, which is presented in the other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $510 million of current liabilities, which is presented in current derivative liabilities in Dominion’s Consolidated Balance Sheet and $151 million of noncurrent liabilities, which is presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet.

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	—	$	66	$	19	$	—	$	47
Commodity contracts:
Over-the-counter	262		63		69		130		191		97		20		74
Exchange	838		505		333		—		393		350		43		—
Total	$	1,100	$	568	$	402	$	130	$	650	$	466	$	63	$	121

The following table presents the volume of Dominion's derivative activity as of December 31, 2013. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)	116		19
Basis(1)	466		281
Electricity (MWh):
Fixed price(1)	14,814,767		14,935,144
FTRs	41,316,345		437,384
Capacity (MW)	83,050		18,300
Liquids (gallons)(2)	151,200,000		—
Interest rate	$	2,050,000,000	$	750,000,000

(1) Includes options.

(2) Includes NGLs and oil.

For the years ended December 31, 2013, 2012 and 2011, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion's Consolidated Balance Sheet at December 31, 2013:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(3	)	$	(3	)	28 months
Electricity	(172		)	(124		)	36 months
Other	(3		)	(3		)	29 months
Interest rate	(110		)	(7		)	364 months
Total	$	(288	)	$	(137	)

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.

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:

	Fair Value  - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At December 31, 2013
ASSETS
Current Assets
Commodity	$	49	$	522	$	571
Interest rate	116		—		116
Total current derivative assets	165		522		687
Noncurrent Assets
Commodity	28		154		182
Interest rate	21		—		21
Total noncurrent derivative assets(1)	49		154		203
Total derivative assets	$	214	$	676	$	890
LIABILITIES
Current Liabilities
Commodity	$	267	$	561	$	828
Total current derivative liabilities	267		561		828
Noncurrent Liabilities
Commodity	119		155		274
Total noncurrent derivative liabilities(2)	119		155		274
Total derivative liabilities	$	386	$	716	$	1,102
At December 31, 2012
ASSETS
Current Assets
Commodity	$	103	$	379	$	482
Interest rate	36		—		36
Total current derivative assets	139		379		518
Noncurrent Assets
Commodity	130		123		253
Interest rate	57		—		57
Total noncurrent derivative assets(1)	187		123		310
Total derivative assets	$	326	$	502	$	828
LIABILITIES
Current Liabilities
Commodity	$	103	$	341	$	444
Interest rate	66		—		66
Total current derivative liabilities	169		341		510
Noncurrent Liabilities
Commodity	58		93		151
Total noncurrent derivative liabilities(2)	58		93		151
Total derivative liabilities	$	227	$	434	$	661

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

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

The following tables present the gains and losses on Dominion's derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified from AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Year Ended December 31, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	(58	)
Purchased gas				(47		)
Electric fuel and other energy-related purchases				(10		)
Total commodity	$	(481	)	$	(115	)	$	5
Interest rate(3)	77			(15		)	81
Total	$	(404	)	$	(130	)	$	86
Year Ended December 31, 2012
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	)

(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.

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2013			2012			2011
(millions)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue	$	(45	)	$	168		$	111
Purchased gas	(9		)	(14		)	(35		)
Electric fuel and other energy-related purchases	(29		)	(40		)	(45		)
Interest rate(2)	—			17			(5		)
Total	$	(83	)	$	131		$	26

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

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

VIRGINIA POWER

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

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	48	$	—	$	48	$	—	$	—	$	—
Commodity contracts:
Over-the-counter	4		—		4		6		—		6
Exchange	1		—		1		—		—		—
Total derivatives, subject to a master netting or similar arrangement	53		—		53		6		—		6
Total derivatives, not subject to a master netting or similar arrangement	—		—		—		—		—		—
Total(1)	$	53	$	—	$	53	$	6	$	—	$	6

(1) At December 31, 2013, the total derivative asset balance contains $53 million of current assets, which is presented in other current assets in Virginia Power’s Consolidated Balance Sheet. At December 31, 2012, the total derivative asset balance contains $6 million of current assets, which is presented in other current assets in Virginia Power’s Consolidated Balance Sheet.

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	48	$	—	$	—	$	48	$	—	$	—	$	—	$	—
Commodity contracts:
Over-the-counter	4		4		—		—		6		3		—		3
Exchange	1		—		—		1		—		—		—		—
Total	$	53	$	4	$	—	$	49	$	6	$	3	$	—	$	3

	December 31, 2013						December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	25	$	—	$	25
Commodity contracts:
Over-the-counter	12		—		12		7		—		7
Exchange	—		—		—		2		—		2
Total derivatives, subject to a master netting or similar arrangement	12		—		12		34		—		34
Total derivatives, not subject to a master netting or similar arrangement	—		—		—		—		—		—
Total(1)	$	12	$	—	$	12	$	34	$	—	$	34

(1) At December 31, 2013, the total derivative liability balance contains $12 million of current liabilities, which is presented in current derivative liabilities in Virginia Power’s Consolidated Balance Sheet. At December 31, 2012, the total derivative liability balance contains $33 million of current liabilities, which is presented in current derivative liabilities in Virginia Power’s Consolidated Balance Sheet and $1 million of noncurrent derivative liabilities, which is presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheet.

			December 31, 2013								December 31, 2012
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	—	$	25	$	—	$	—	$	25
Commodity contracts:
Over-the-counter	12		4		7		1		7		3		—		4
Exchange	—		—		—		—		2		—		2		—
Total	$	12	$	4	$	7	$	1	$	34	$	3	$	2	$	29

The following table presents the volume of Virginia Power's derivative activity at December 31, 2013. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price	15		—
Basis	7		—
Electricity (MWh):
Fixed price	624,800		—
FTRs	39,186,609		—
Capacity (MW)	75,500		18,300
Interest rate	$	600,000,000	$	—

For the years ended December 31, 2013, 2012 and 2011, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to 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:

	Fair Value  - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At December 31, 2013
ASSETS
Current Assets
Commodity	$	2	$	3	$	5
Interest rate	48				48
Total current derivative assets(1)	50		3		53
Total derivative assets	$	50	$	3	$	53
LIABILITIES
Current Liabilities
Commodity	$	1	$	11	$	12
Total current derivative liabilities	1		11		12
Total derivative liabilities	$	1	$	11	$	12
At December 31, 2012
ASSETS
Current Assets
Commodity	$	1	$	5	$	6
Total current derivative assets(1)	1		5		6
Total derivative assets	$	1	$	5	$	6
LIABILITIES
Current Liabilities
Commodity	$	5	$	3	$	8
Interest rate	25		—		25
Total current derivative liabilities	$	30	$	3	$	33
Noncurrent Liabilities
Commodity	1		—		1
Total noncurrent derivative liabilities(2)	1		—		1
Total derivative liabilities	$	31	$	3	$	34

(1) Current derivative assets are presented in other current assets in Virginia Power's Consolidated Balance Sheets.

(2) 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	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)
Year Ended December 31, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	—
Total commodity	$	—		$	—		$	5
Interest rate(3)	9			—			81
Total	$	9		$	—		$	86
Year Ended December 31, 2012
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	)

(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.

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2013			2012			2011
(millions)
Derivative Type and Location of Gains (Losses)
Commodity(2)	$	(16	)	$	(50	)	$	(45	)
Interest rate(3)	—			—			(5		)
Total	$	(16	)	$	(50	)	$	(50	)

(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

Variable Interest Entities (Narrative) (Details) (USD $)	12 Months Ended			1 Months Ended	110 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Aug. 31, 2013 Juniper	Aug. 31, 2013 Juniper	Oct. 31, 2011 Juniper	Dec. 31, 2013 Virginia Electric and Power Company MW	Dec. 31, 2012 Virginia Electric and Power Company	Dec. 31, 2011 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							$ 900,000,000
Payment for electric capacity							217,000,000	214,000,000	211,000,000
Payment for electric energy							98,000,000	83,000,000	125,000,000
Shared services purchased							331,000,000	328,000,000	389,000,000
Annual lease payments					53,000,000
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
Acquisition of Juniper noncontrolling interest in Fairless	$ 923,000,000	$ 0	$ 0	$ 923,000,000

XML

Property, Plant and Equipment (Share of Jointly-Owned Power Stations) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Millstone Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	93.50%	[1]
Plant in service	$ 1,007	[1]
Accumulated depreciation	(262)	[1]
Nuclear fuel	388	[1]
Accumulated amortization of nuclear fuel	(283)	[1]
Plant under construction	69	[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	1,038	[2]
Accumulated depreciation	(536)	[2]
Nuclear fuel	0	[2]
Accumulated amortization of nuclear fuel	0	[2]
Plant under construction	23	[2]
Virginia Electric and Power Company | North Anna
Jointly Owned Utility Plant Interests [Line Items]
Ownership interest	88.40%	[2]
Plant in service	2,486	[2]
Accumulated depreciation	(1,109)	[2]
Nuclear fuel	597	[2]
Accumulated amortization of nuclear fuel	(434)	[2]
Plant under construction	76	[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	(199)	[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

Property, Plant and Equipment (Narrative) (Details) (Oil and Gas Properties, USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	Dec. 31, 2013 Natural_Gas_Producer acre	Dec. 31, 2013 acre
Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Number of natural gas producers	2
Acres of Marcellus Shale rights	100,000	100,000
Agreed upon payments for conveyance of acres of natural gas storage fields	$ 200	$ 200
Period for payments related to conveyance of natural gas storage fields	9 years
Cash proceeds received from sale		100
Gain from sale		20
After tax gain on sale		12
Deferred Revenue, Additions		$ 80

XML

Employee Benefit Plans (Benefit Payments Expected Future Service) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2014	$ 264
2015	269
2016	283
2017	300
2018	319
2019-2023	1,868
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
2014	91
2015	93
2016	96
2017	98
2018	100
2019-2023	$ 507

XML

Commitments and Contingencies (Nuclear Insurance) (Details) (USD $)	Dec. 31, 2013
Millstone
Guarantor Obligations [Line Items]
Property insurance coverage	$ 1,700,000
Kewaunee
Guarantor Obligations [Line Items]
Property insurance coverage	1,060,000
Surry | Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Property insurance coverage	1,700,000	[1]
North Anna | Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Property insurance coverage	1,700,000	[1]
Surry and North Anna
Guarantor Obligations [Line Items]
Coverage amount	$ 450,000,000.000

[1] Surry and North Anna share a blanket property limit of $450 million.

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	3 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Changes in fair value of plan assets:
Actual return on plan assets		$ 959		$ 743
Employer contributions		40		40		38
Pension Benefits
Changes in benefit obligation:
Service cost		131		116		108
Interest cost		271		268		258
Medicare Part D reimbursement	354
Changes in fair value of plan assets:
Discount rate	4.80%
Other Postretirement Benefits
Changes in benefit obligation:
Service cost		43		44		48
Interest cost		73		79		94
Medicare Part D reimbursement	78
Changes in fair value of plan assets:
Discount rate	4.70%	4.80%
Changes In Benefit Obligation | Pension Benefits
Changes in benefit obligation:
Benefit obligation at beginning of year		6,125		4,981
Service cost		131		116
Interest cost		271		268
Benefits paid		(229)		(208)
Actuarial (gains) losses during the year		(650)		967
Plan amendments		1	[1]	1	[1]
Settlements and curtailments		(24)	[2]	0	[2]
Special termination benefits		0		0
Medicare Part D reimbursement		0		0
Benefit obligation at end of year		5,625		6,125
Changes In Benefit Obligation | Other Postretirement Benefits
Changes in benefit obligation:
Benefit obligation at beginning of year		1,719		1,493
Service cost		43		44
Interest cost		73		79
Benefits paid		(75)		(88)
Actuarial (gains) losses during the year		(170)		191
Plan amendments		(220)	[1]	1	[1]
Settlements and curtailments		(16)	[2]	(6)	[2]
Special termination benefits		1		0
Medicare Part D reimbursement		5		5
Benefit obligation at end of year		1,360		1,719
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		5,553		5,145
Actual return on plan assets		781		611
Employer contributions		8		5
Benefits paid		(229)		(208)
Fair value of plan assets at end of year		6,113		5,553
Funded status at end of year		488		(572)
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		1,156		1,042
Actual return on plan assets		178		132
Employer contributions		12		16
Benefits paid		(31)		(34)
Fair value of plan assets at end of year		1,315		1,156
Funded status at end of year		(45)		(563)
Level 1 | Pension Benefits
Changes in fair value of plan assets:
Noncurrent pension and other postretirement benefit assets		913		701
Other current liabilities		(15)		(2)
Noncurrent pension and other postretirement benefit liabilities		(410)		(1,271)
Net amount recognized		488		(572)
Level 1 | Other Postretirement Benefits
Changes in fair value of plan assets:
Noncurrent pension and other postretirement benefit assets		29		1
Other current liabilities		(3)		(4)
Noncurrent pension and other postretirement benefit liabilities		(71)		(560)
Net amount recognized		$ (45)		$ (563)
Level 2 | Pension Benefits
Changes in fair value of plan assets:
Discount rate				4.40%	[3]
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%	[3]
Weighted average rate of increase for compensation		4.22%		4.22%
Minimum | Level 2 | Pension Benefits
Changes in fair value of plan assets:
Discount rate		5.20%	[3]
Minimum | Level 2 | Other Postretirement Benefits
Changes in fair value of plan assets:
Discount rate		5.00%	[3]
Maximum | Level 2 | Pension Benefits
Changes in fair value of plan assets:
Discount rate		5.30%	[3]
Maximum | Level 2 | Other Postretirement Benefits
Changes in fair value of plan assets:
Discount rate		5.10%	[3]

[1] Relates to a plan amendment that changed medical coverage for certain Medicare-eligible retirees.

[2] 2013 amounts relate primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor.

[3] Pension rates are 5.20% for the gas union plans and 5.30% for the nonunion and other union plans. OPEB rates are 5.00% for the gas union plans and 5.10% for the nonunion and other union plans.

XML

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
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		581,483,227
Entity Well Known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 32,100,000,000
Virginia Electric and Power Company
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
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

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, 2013		Dec. 31, 2012		Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	$ (554)		$ (509)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Settlements and curtailments	220
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	131		116		108
Interest cost	271		268		258
Expected return on plan assets	(462)		(430)		(440)
Amortization of prior service (credit) cost	3		3		3
Amortization of net actuarial loss	165		132		96
Settlements and curtailments	(2)	[1]	0	[1]	0	[1]
Special termination benefits	0		0		0
Net periodic benefit cost	106		89		25
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	(968)		786		534
Prior service (credit) cost	1		0		0
Settlements and curtailments	(22)	[1]	0	[1]	0	[1]
Amortization of net actuarial loss	165		132		96
Amortization of prior service credit (cost)	(3)		(3)		(3)
Total recognized in other comprehensive income and regulatory assets and liabilities	(1,157)		651		435
Significant assumptions used to determine periodic cost:
Discount rate			5.50%		5.90%
Expected long-term rate of return on plan assets	8.50%		8.50%		8.50%
Weighted average rate of increase for compensation	4.21%		4.21%		4.61%
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	43		44		48
Interest cost	73		79		94
Expected return on plan assets	(92)		(79)		(79)
Amortization of prior service (credit) cost	(15)		(13)		(13)
Amortization of net actuarial loss	7		6		12
Settlements and curtailments	(15)	[1]	(4)	[1]	1	[1]
Special termination benefits	(1)				0
Net periodic benefit cost	2		33		63
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	(255)		139		(157)
Prior service (credit) cost	(215)		1		(70)
Settlements and curtailments	(7)	[1]	(2)	[1]	(1)	[1]
Amortization of net actuarial loss	7		6		12
Amortization of prior service credit (cost)	15		13		13
Total recognized in other comprehensive income and regulatory assets and liabilities	$ (469)		$ 145		$ (227)
Significant assumptions used to determine periodic cost:
Discount rate			5.50%		5.90%
Expected long-term rate of return on plan assets	7.75%		7.75%		7.75%
Weighted average rate of increase for compensation	4.22%		4.22%		4.62%
Healthcare cost trend rate	7.00%	[2]	7.00%	[2]	7.00%	[2]
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	4.60%	[2]	4.60%	[2]	4.60%	[2]
Year that the rate reaches the ultimate trend rate	2062	[2]	2061	[2]	2060	[2]
Minimum | Pension Benefits
Significant assumptions used to determine periodic cost:
Discount rate	4.40%
Minimum | Other Postretirement Plans
Significant assumptions used to determine periodic cost:
Discount rate	4.40%
Maximum | Pension Benefits
Significant assumptions used to determine periodic cost:
Discount rate	4.80%
Maximum | Other Postretirement Plans
Significant assumptions used to determine periodic cost:
Discount rate	4.80%

[1] 2013 amount relates primarily to the decommissioning of Kewaunee. 2012 amount relates to the sale of Salem Harbor.

[2] Assumptions used to determine periodic cost for the following year.

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Earnings Per Share

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

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

	2013		2012		2011
(millions, except EPS)
Net income attributable to Dominion	$	1,697	$	302	$	1,408
Average shares of common stock outstanding-Basic	578.7		572.9		573.1
Net effect of dilutive securities(1)	0.8		1.0		1.5
Average shares of common stock outstanding-Diluted	579.5		573.9		574.6
Earnings Per Common Share-Basic	$	2.93	$	0.53	$	2.46
Earnings Per Common Share-Diluted	$	2.93	$	0.53	$	2.45

(1) Dilutive securities consist primarily of contingently convertible senior notes. See Note 17 for more information.

Dominion's 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013 are potentially dilutive securities but were excluded from the calculation of diluted EPS for the year ended December 31, 2013.  See Note 17 for more information. There were no potentially dilutive securities excluded from the calculation of diluted EPS for the years ended December 31, 2012 and 2011.

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Derivatives and Hedge Accounting Activities (Selected Information Related to Gains (Losses) on Cash Flow Hedges Included in AOCI) (Details) (USD $) In Millions, unless otherwise specified			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Commodity Gas	Dec. 31, 2013 Commodity Electricity	Dec. 31, 2013 Commodity Other	Dec. 31, 2013 Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ (288)	$ (122)	$ (3)	$ (172)	$ (3)	$ (110)
Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax	$ (137)		$ (3)	$ (124)	$ (3)	$ (7)
Maximum Term			28 months	36 months	29 months	364 months

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Investments (Investments Under Equity Method of Accounting) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 916		$ 558
Commitment to invest in clean power and technology	50
Blue Racer Midstream LLC
Schedule of Equity Method Investments [Line Items]
Ownership%	50.00%
Investment Balance	510		39
Description	Midstream gas and related services
Fowler I Holdings LLC
Schedule of Equity Method Investments [Line Items]
Ownership%	50.00%
Investment Balance	149		158
Description	Wind-powered merchant generation facility
NedPower Mount Storm LLC
Schedule of Equity Method Investments [Line Items]
Ownership%	50.00%
Investment Balance	131		137
Description	Wind-powered merchant generation facility
Iroquois Gas Transmission System, LP
Schedule of Equity Method Investments [Line Items]
Ownership%	24.72%
Investment Balance	105		102
Description	Gas transmission system
Elwood Energy LLC
Schedule of Equity Method Investments [Line Items]
Ownership%	0.00%	[1]	50.00%	[1]
Investment Balance	0	[1]	117	[1]
Description	Natural gas-fired merchant generation peaking facility	[1]
Ownership retained in cost method investment	0.50%	[1]
Other
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 21	[2]	$ 5	[2]

[1] Following the 2013 sale of Elwood, at December 31, 2013, Dominion retained a 0.5% cost method investment. At December 31, 2012, Dominion owned 50% and Elwood was therefore considered an equity method investment.

[2] Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018.

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Net income including noncontrolling interests	$ 1,720	$ 329	[1]	$ 1,426	[1]
Net income attributable to Dominion	1,697	302	[1]	1,408	[1]
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of tax	(243)	(8)		(67)
Changes in unrealized net gains (losses) on investment securities, net of tax	203	108		11
Changes in net unrecognized pension and other postretirement benefit costs, net of tax	516	(330)		(231)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of tax	77	(60)		(38)
Net realized gains on investment securities, net of tax	(55)	(25)		6
Net pension and other postretirement benefit costs, net of tax	55	48		39
Total other comprehensive income income (loss)	553	(267)		(280)
Comprehensive income including noncontrolling interests	2,273	62		1,146
Comprehensive income attributable to noncontrolling interests	23	27		18
Comprehensive income	2,250	35		1,128
Virginia Electric and Power Company
Net income attributable to Dominion	1,138	1,050		822
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of tax	6	(5)		(6)
Changes in unrealized net gains (losses) on investment securities, net of tax	20	13		2
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of tax	0	2		(1)
Net realized gains on investment securities, net of tax	(3)	(4)		0
Total other comprehensive income income (loss)	23	6		(5)
Comprehensive income	$ 1,161	$ 1,056		$ 817

[1] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

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 2012 and 2011 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2013 presentation for comparative purposes. The reclassifications did not affect the Companies' net income, total assets, liabilities, equity or cash flows.

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

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, 2013 and 2012 included $555 million and $411 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, 2013 and 2012 included $395 million and $348 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;

• 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 84% 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. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, 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.

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 2013, Dominion recognized interest income of $3 million and interest expense of $10 million and no penalties. In 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. Dominion had accrued interest receivable of $5 million, interest payable of $15 million and penalties payable of less than $1 million at December 31, 2013 and interest receivable of $5 million, interest payable of $10 million and penalties payable of less than $1 million at December 31, 2012.

Virginia Power's interest and penalties were immaterial in 2013 and 2012. In 2011, Virginia Power recognized interest income of $12 million, and penalties were immaterial.

At December 31, 2013, Virginia Power's Consolidated Balance Sheet included $3 million of state income taxes receivable, $22 million of federal and state income taxes payable, $12 million of noncurrent state income taxes receivable and $28 million of noncurrent federal and state income taxes payable.

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.

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, 2013 and 2012, Dominion's accounts payable included $38 million and $53 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 2013 and 2012, Virginia Power's accounts payable included $21 million and $30 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 $620 million and $212 million associated with cash collateral at December 31, 2013 and 2012, respectively. Dominion had margin liabilities of $2 million and $4 million associated with cash collateral at December 31, 2013 and 2012, respectively. Virginia Power had margin assets of $11 million and $18 million associated with cash collateral at December 31, 2013 and 2012, respectively. Virginia Power's margin liabilities associated with cash collateral were not material at December 31, 2013 and 2012. See Note 7 for further information about offsetting derivatives.

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 is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, 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 generally charged to expense as it is incurred.

In 2013, 2012 and 2011, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $66 million, $91 million and $85 million, respectively. In 2013, 2012 and 2011, Virginia Power capitalized AFUDC to property, plant and equipment of $33 million, $31 million and $31 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 2013, 2012 and 2011, Virginia Power recorded $32 million, $37 million and $20 million of AFUDC related to these projects, respectively.

For property subject to cost-of-service rate regulation, including Virginia Power 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 average composite depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2013	2012	2011
(percent)
Dominion
Generation	2.71	2.62	2.68
Transmission	2.36	2.17	2.26
Distribution	3.13	3.17	3.19
Storage	2.43	2.59	2.64
Gas gathering and processing	2.39	2.49	2.52
General and other	3.82	4.55	4.66
Virginia Power
Generation	2.71	2.62	2.68
Transmission	2.28	1.98	2.03
Distribution	3.33	3.32	3.33
General and other	3.51	4.32	4.38

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	44 years
Merchant generation-other	15-36 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.

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. At least annually, the Companies evaluate the key assumptions underlying their AROs including estimates of the amounts and timing of future cash flows associated with retirement activities. AROs are adjusted when significant changes in these assumptions are identified. Dominion reports accretion of AROs and depreciation on asset retirement costs 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 and depreciation on asset retirement costs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs is reported in other operations and maintenance expense and depreciation 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 AOCI. 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 $7 million and $24 million at December 31, 2013 and December 31, 2012, respectively. Based on the average price of gas purchased during 2013 and 2012, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $77 million and $69 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.

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Nature of Operations

12 Months Ended

Dec. 31, 2013

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, transport 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.

In the second quarter of 2013, Dominion commenced a restructuring of its producer services business. The restructuring will result in the termination of natural gas trading and certain energy marketing activities. The restructuring is intended to reduce producer services' earnings volatility, and is not expected to have a material impact on Dominion's business.

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 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.

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Regulatory Matters

12 Months Ended

Dec. 31, 2013

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

FERC - Electric

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

Rates

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

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 2014 is $857 million and the remaining projects were completed by 2012.  Numerous parties sought rehearing of the FERC order in August 2008. In May 2012, FERC issued an order denying the rehearing requests.  In July 2012, the North Carolina Commission filed an appeal of the FERC orders with the U.S. Court of Appeals for the Fourth Circuit. In January 2014, the court rejected the appeal and affirmed FERC's decision granting the incentives.

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.

Other Regulatory Matters

Electric Regulation in Virginia

The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia's planned transition to retail competition for electric supply service to most classes of customers.

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, and also constitutes statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly proposed generation projects.

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.

2013 Biennial Review

Pursuant to the Regulation Act, in March 2013, Virginia Power submitted its base rate filings and accompanying schedules in support of the Virginia Commission's 2013 biennial review of Virgina Power's rates, terms and conditions, as well as of Virginia Power's earnings for 2011 and 2012 test periods. The Virginia Power earnings test analysis reviewed by the Virginia Commission reflected an ROE of 10.30% on its generation and distribution services earnings for the combined test periods.

In November 2013, the Virginia Commission issued its 2013 Biennial Review Order. After deciding eleven contested earnings test adjustments, the Virginia Commission ruled that Virginia Power earned on average an ROE of approximately 10.25% on its generation and distribution services for the combined 2011 and 2012 test periods. Because this ROE was more than 50 basis points below Virginia Power’s authorized ROE of 10.9%, the Virginia Commission authorized the deferred recovery, for earnings test purposes, of $23 million in costs related to asset impairments with early retirement decisions, severe weather events, and natural disasters to be amortized over the 2013 calendar year. The Virginia Commission did not order a base rate increase because Virginia Power had previously waived its right to any such increase, and because it determined that Virginia Power had a revenue sufficiency of approximately $280 million when projecting the annual revenues generated by base rates to the revenues required to cover costs of service and earn a fair return. As part of its revenue sufficiency determination, the Virginia Commission also made findings on eleven rate case adjustments, in addition to changes to the cost of capital and capital structure, which resulted in changes to Virginia Power’s rate year revenues and expenses, and Virginia Power’s rate base for generation and distribution, for the rate year beginning January 1, 2014. Virginia Power incurred a $55 million ($37 million after-tax) charge in connection with the 2013 Biennial Review Order.

In its 2013 Biennial Review Order, the Virginia Commission also set the ROE that will be used in Virginia Power’s 2015 biennial review earnings test analysis for earnings on generation and distribution services for the combined 2013 and 2014 test periods, and that will be applied to Riders R, S, W, B, BW, C1A, and C2A. Pursuant to the Regulation Act, Virginia Power’s authorized ROE can be no lower than the average of the returns reported for the three previous years by not less than a majority of comparable utilities in the Southeastern U.S., subject to certain limitations as described in the Regulation Act. Following this statutory peer group analysis, the Virginia Commission determined that the peer group floor ROE for Virginia Power was 9.89%. It further held, declining to increase or decrease Virginia Power’s combined rate of return based on performance, that Virginia Power’s ROE for earnings test purposes in its 2015 biennial review and for rate adjustment clause purposes is 10.0%, consistent with its determination that Virginia Power’s market cost of equity is 10.0%.

Virginia Fuel Expenses

In May 2013, Virginia Power submitted its annual fuel factor filing to the Virginia Commission, proposing an increase of approximately $162 million in fuel revenue for the rate year beginning July 1, 2013. In June 2013, the Virginia Commission issued an order approving the rate.

In November 2013, the Virginia Commission approved Virginia Power’s voluntary request to reduce Virginia Power’s currently-approved fuel factor rate from 2.942 ¢/kWh to 2.572 ¢/kWh effective for usage on and after December 1, 2013, due to an expected over-recovery of fuel costs. This request is expected to reduce Virginia Power’s anticipated fuel recoveries through June 30, 2014 by more than $140 million. At December 31, 2013, Virginia Power's Consolidated Balance Sheets reflected $24 million of other current liabilities and $85 million of noncurrent regulatory liabilities related to the over-recovered fuel costs.

Rate Adjustment Clauses

Below is a discussion of significant riders associated with various Virginia Power projects:

• In 2012, the Virginia Commission approved the conversion of the Altavista, Hopewell, and Southampton power stations to biomass, and in conjunction approved Rider B. Virginia Power proposed an approximately $16 million revenue requirement for the rate year beginning April 1, 2014. This case is pending.

• In 2013, the Virginia Commission approved Virginia Power's request to construct and operate Brunswick County, and in conjunction approved the associated transmission facilities and Rider BW. Virginia Power proposed an approximately $101 million revenue requirement for the rate year beginning September 1, 2014. This case is pending.

• The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. Virginia Power proposed an approximately $248 million revenue requirement for the rate year beginning April 1, 2014. This case is pending.

• The Virginia Commission previously approved Rider W in conjunction with Warren County. Virginia Power proposed an approximately $101 million total revenue requirement for the rate year beginning April 1, 2014. This case is pending.

• The Virginia Commission approved Riders C1A and C2A in connection with various DSM programs. The requested revenue requirements are approximately $1 million for Rider C1A and approximately $35 million for Rider C2A. This case is pending.

• In May 2013, Virginia Power filed for an adjustment to its current Rider T1 with the Virginia Commission for the rate year beginning September 1, 2013, which reflects a total revenue requirement of approximately $404 million.  In July 2013, the Virginia Commission issued an order approving the rate.

Bremo Power Station

In September 2013, the Virginia Commission issued its final order approving an amended and reissued CPCN that would allow Virginia Power to convert Bremo Units 3 and 4 from using coal to natural gas as their fuel source. The proposed conversion will preserve 227 MW (net) of existing capacity and is expected to cost approximately $53 million, excluding financing costs.

North Anna

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

If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. Virginia Power filed the first of its two-part amendment to the COL application with the NRC in July 2013 to reflect the ESBWR technology, and filed the second part of the amendment in December 2013. A COL is expected in 2015. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

In May 2013, BREDL filed a motion with the NRC ASLB to reopen the COL adjudicatory proceeding relating to North Anna based on new information, citing the change in reactor technology. The motion did not propose any new contentions but asked that either (i) the proceeding be restarted from the beginning by submittal of a new application and renoticing in the Federal Register, or (ii) the proceeding be reopened pending submittal of new contentions, which BREDL would be given an extended amount of time to file.

In July 2013, the ASLB issued an order holding BREDL’s motion in abeyance. The ASLB noted that because BREDL proposed no contentions, it could not determine whether any portion of the motion falls within the ASLB’s jurisdiction, which is currently limited to ruling on a September 2011 petition filed by BREDL to reopen the COL proceeding related to seismic issues. In January 2014, Virginia Power informed the ASLB and parties that the Company’s assessment of seismic issues was complete. Under a previous ruling of the ASLB, BREDL will have a period of 60 days from the time Virginia Power informs the NRC and parties that its seismic assessment is complete to submit a motion to reopen the proceeding on this topic.

Legislation has been proposed that would limit the portion of costs incurred by an investor-owned electric utility between July 1, 2007 and December 31, 2013, in developing a nuclear power facility or an offshore wind project that are recoverable from Virginia jurisdictional and non-jurisdictional customers through a future rate adjustment clause to a maximum of 30% of such amount. Virginia Power has deferred or capitalized costs totaling $570 million as of December 31, 2013 related to the development of a third nuclear unit site located at North Anna. If this proposed legislation is enacted, 70% of the costs previously deferred or capitalized would be recovered from Virginia jurisdictional and non-jurisdictional ratepayers as part of the 2013 and 2014 base rates. Upon enactment, Virginia Power would recognize 70% of the costs previously deferred or capitalized against net income in 2014. The remaining deferred or capitalized costs, as well as costs incurred after December 31, 2013, would continue to be eligible for inclusion in a future rate adjustment clause.

Electric Transmission Projects

In January 2013, a notice of appeal was filed with the Supreme Court of Virginia by a private party regarding the Virginia Commission's December 2012 order granting a CPCN and authorizing construction of the Waxpool-Brambleton-BECO line. In October 2013, the Supreme Court of Virginia issued an opinion affirming the Virginia Commission’s decision.

In October 2013, Virginia Power applied for a CPCN to rebuild within existing rights-of-way its existing 500 kV Loudoun-Pleasant View transmission line in Loudoun County. As stated in the application, the project is needed to address NERC Reliability Standards violations projected to occur in 2016 and to replace aging transmission facilities. This case is pending.

In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry Switching Station in Surry County to a new Skiffes Creek Switching Station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek Switching Station to Virginia Power’s existing Whealton Substation in the City of Hampton. In December 2013, Virginia Power filed a motion for reconsideration to the Virginia Commission and a notice to appeal the Virginia Commission's order to the Supreme Court of Virginia. The Virginia Commission granted reconsideration and ordered a hearing, which was held in January 2014. The matter is pending at the Virginia Commission. The projected in-service date for this transmission project has been delayed until December 2015 at the earliest.

Ohio Regulation

PIR Program

In 2008, East Ohio began PIR, aimed at replacing approximately 20% of its pipeline system, or approximately 4,100 miles, over a 25-year period. In February 2013, East Ohio filed an application with the Ohio Commission to adjust the cost recovery charge for costs associated with PIR investments for the calendar year 2012 and cumulatively. The application includes total gross plant investment for 2012 of $148 million, cumulative gross plant investment of $511 million, and a revenue requirement of $67 million. The Ohio Commission issued an order approving the rates in April 2013. In May 2013, the approved PIR cost recovery rates became effective.

In November 2013, East Ohio filed a notice to adjust the PIR cost recovery for 2013 costs. The filing reflects projected gross plant investment for 2013 of $170 million, cumulative gross plant investment of $681 million and an estimated revenue requirement of approximately $90 million. This case is pending.

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 payment plan amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. In July 2013, the Ohio Commission approved East Ohio's annual update of the PIPP Rider, which reflects the refund over the next year of an over-recovery of accumulated arrearages of approximately $91 million as of March 31, 2013, net of projected deferred program costs of approximately $54 million for the period from April 2013 through June 2014.

FERC Regulation

DTI Fuel Settlement

In mid-2013, DTI received concerns about its fuel retainage percentages and apparent over-recovery of fuel costs during certain time periods reflected in its annual fuel reports. In December 2013, DTI submitted for FERC approval a stipulation and agreement addressing, among other things, reductions in its fuel retainage percentages. 

In February 2014, FERC approved the stipulation and agreement. DTI will implement the reduced fuel retainage percentages effective March 1, 2014. DTI will also provide refunds with interest to each settling customer reflecting the value of the actual quantities of fuel retained from that party between January 1, 2014 and the March 1, 2014 implementation date. This agreement is expected to reduce DTI’s revenues by approximately $35 million in 2014.

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Investments

12 Months Ended

Dec. 31, 2013

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 $107 million and $95 million at December 31, 2013 and 2012, respectively. Cost-method investments held in Dominion's rabbi trusts totaled $10 million and $14 million at December 31, 2013 and 2012, 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)
2013
Marketable equity securities:
U.S.:
Large Cap	$	1,183	$	1,194	$	—			$	2,377
Other	49		23		—				72
Marketable debt securities:
Corporate debt instruments	332		16		(3		)		345
U.S. Treasury securities and agency debentures	589		8		(10		)		587
State and municipal	297		11		(5		)		303
Other	3		—		—				3
Cost method investments	106		—		—				106
Cash equivalents and other(2)	110		—		—				110
Total	$	2,669	$	1,252	$	(18	)	(3)	$	3,903
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

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

(2) Includes pending sales of securities of $11 million and pending purchases of securities of $6 million at December 31, 2013 and 2012, respectively.

(3) The fair value of securities in an unrealized loss position was $604 million and $195 million at December 31, 2013 and 2012, respectively.

The fair value of Dominion's marketable debt securities held in nuclear decommissioning trust funds at December 31, 2013 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	128
Due after one year through five years	357
Due after five years through ten years	362
Due after ten years	391
Total	$	1,238

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

Year Ended December 31,	2013		2012		2011
(millions)
Proceeds from sales	$	1,476	$	1,356	$	1,757
Realized gains(1)	157		98		79
Realized losses(1)	33		33		92

(1) 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,	2013			2012			2011
(millions)
Total other-than-temporary impairment losses(1)	$	31		$	26		$	75
Losses recorded to decommissioning trust regulatory liability	(13		)	(10		)	(24		)
Losses recognized in other comprehensive income (before taxes)	(10		)	(2		)	(3		)
Net impairment losses recognized in earnings	$	8		$	14		$	48

(1) Amounts include other-than-temporary impairment losses for debt securities of $18 million, $4 million and $6 million at December 31, 2013, 2012 and 2011, 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,			2013		2012
(millions)
Blue Racer Midstream LLC	50	%	$	510	$	39	Midstream gas and related services
Fowler I Holdings LLC	50	%	149		158		Wind-powered merchant generation facility
NedPower Mount Storm LLC	50	%	131		137		Wind-powered merchant generation facility
Iroquois Gas Transmission System, LP	24.72	%	105		102		Gas transmission system
Elwood Energy LLC(1)	—	%	—		117		Natural gas-fired merchant generation peaking facility
Other(2)	various		21		5
Total			$	916	$	558

(1) Following the 2013 sale of Elwood, at December 31, 2013, Dominion retained a 0.5% cost method investment. At December 31, 2012, Dominion owned 50% and Elwood was therefore considered an equity method investment.

(2) Dominion has a $50 million commitment to invest in clean power and technology businesses through 2018.

Dominion's equity earnings on these investments totaled $14 million, $25 million and $35 million in 2013, 2012 and 2011, respectively. Dominion received distributions from these investments of $33 million, $58 million and $55 million in 2013, 2012, and 2011, respectively. As of December 31, 2013 and 2012, the carrying amount of Dominion's investments exceeded Dominion's share of underlying equity in net assets by approximately $36 million and $30 million, respectively. $28 million of 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, which are being amortized over the useful lives of the underlying assets. The remaining $8 million of differences reflect equity method goodwill and are not being amortized.

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.

In March 2013, Dominion sold Line TL-404 to Blue Racer and received approximately $47 million in cash proceeds resulting in an approximately $25 million ($14 million after-tax) gain. Phase 1 of the Natrium natural gas processing and fractionation facility was completed in the second quarter of 2013 and was contributed to Blue Racer in the third quarter of 2013, resulting in an increased equity method investment in Blue Racer of $473 million. Also in the third quarter of 2013, Dominion sold Line TPL-2A and Line TL-388 to Blue Racer and received approximately $83 million in cash proceeds resulting in an approximately $75 million ($42 million after-tax) gain. In the fourth quarter of 2013, Dominion sold the Western System to Blue Racer for $30 million in cash proceeds resulting in an approximately $4 million ($2 million after-tax) gain. Dominion NGL Pipelines, LLC was contributed in January 2014 to Blue Racer prior to commencement of service, resulting in an increased equity method investment of $155 million.

The joint venture is leveraging 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 include gathering, processing, fractionation, and NGL transportation and marketing. In addition to the assets already sold or contributed, Dominion expects to sell additional East Ohio gathering assets to Blue Racer.

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)
2013
Marketable equity securities:
U.S.:
Large Cap	$	506	$	514	$	—			$	1,020
Other	25		11		—				36
Marketable debt securities:
Corporate debt instruments	185		8		(2		)		191
U.S. Treasury securities and agency debentures	214		1		(3		)		212
State and municipal	163		4		(4		)		163
Cost method investments	106		—		—				106
Cash equivalents and other(2)	37		—		—				37
Total	$	1,236	$	538	$	(9	)	(3)	$	1,765
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

(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

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

(3) The fair value of securities in an unrealized loss position was $299 million and $104 million at December 31, 2013 and 2012, respectively.

The fair value of Virginia Power's debt securities at December 31, 2013, by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	31
Due after one year through five years	163
Due after five years through ten years	196
Due after ten years	176
Total	$	566

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

Year Ended December 31,	2013		2012		2011
(millions)
Proceeds from sales	$	572	$	626	$	1,030
Realized gains(1)	52		42		34
Realized losses(1)	14		11		34

(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,	2013			2012			2011
(millions)
Total other-than-temporary impairment losses(1)	$	15		$	11		$	29
Losses recorded to decommissioning trust regulatory liability	(13		)	(10		)	(24		)
Losses recorded in other comprehensive income (before taxes)	(1		)	—			(1		)
Net impairment losses recognized in earnings	$	1		$	1		$	4

(1) Amounts include other-than-temporary impairment losses for debt securities of $9 million, $2 million and $4 million at December 31, 2013, 2012 and 2011, 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, 2013 and 2012, Dominion had $11 million and $37 million, respectively, and Virginia Power had $8 million and $10 million, respectively, of restricted cash and cash equivalents. These balances are presented in Other Current Assets and Other Investments in the Consolidated Balance Sheets.

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Earnings Per Share (Calculation of our Basic and Diluted EPS) (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended									12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Earnings Per Share [Abstract]
Net income attributable to Dominion	$ 431	[1]	$ 569	$ 202	$ 495	$ (659)	$ 209	$ 258	$ 494	$ 1,697		$ 302	[2]	$ 1,408	[2]
Average shares of common stock outstanding-Basic										578,700,000		572,900,000		573,100,000
Net effect of potentially dilutive securities										800,000	[3]	1,000,000	[3]	1,500,000	[3]
Average shares of common stock outstanding-Diluted										579,500,000		573,900,000		574,600,000
Earnings Per Common Share-Basic (in dollars per share)	$ 0.74	[1]	$ 0.98	$ 0.35	$ 0.86	$ (1.15)	$ 0.36	$ 0.45	$ 0.86	$ 2.93		$ 0.53	[2]	$ 2.46	[2]
Earnings Per Common Share-Diluted (in dollars per share)	$ 0.74	[1]	$ 0.98	$ 0.35	$ 0.86	$ (1.15)	$ 0.36	$ 0.45	$ 0.86	$ 2.93		$ 0.53	[2]	$ 2.45	[2]
Potentially dilutive securities excluded from the calculation of diluted EPS												0		0

[1] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3.

[2] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

[3] Dilutive securities consist primarily of contingently convertible senior notes. See Note 17 for more information.

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [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% bonus depreciation allowance for qualifying capital expenditures incurred through 2013.

In September 2013, the IRS issued final regulations that provide guidance to taxpayers on the treatment of amounts paid to acquire, produce or improve tangible property, including whether expenditures should be deducted as repairs or capitalized and depreciated on tax returns. The final regulations include a number of safe harbor tax accounting methods which a taxpayer may choose to elect and, if adopted, will not be challenged by the IRS. In addition, the IRS reissued certain temporary regulations that were also issued concurrently as proposed regulations regarding property dispositions. The final regulations are effective for tax years beginning on or after January 1, 2014.  Although changes in tax accounting methods would be effective prospectively, implementation of certain changes will require a calculation of the cumulative effect of the change on prior years. Under IRS procedural guidance issued in January 2014, if such cumulative effect increases taxable income, it is includible in taxable income over a four-year period, beginning with the year of the change. However, if such cumulative effect decreases taxable income, the entire amount is includible in taxable income in the year of the change.

Dominion and Virginia Power have evaluated tax accounting method changes that may be elected or required by the final regulations. At December 31, 2013, $17 million of deferred tax liabilities have been classified as current in the Companies’ Consolidated Balance Sheets, representing cumulative adjustment amounts expected to be reflected in income for tax purposes during the twelve months ending December 31, 2014. Tax accounting method changes in 2014 are not expected to materially affect the Companies’ cash flows, results of operations or financial condition.

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,	2013			2012			2011			2013			2012			2011
(millions)
Current:
Federal	$	317		$	43		$	31		$	357		$	70		$	(35	)
State	110			84			16			62			81			79
Total current expense	427			127			47			419			151			44
Deferred:
Federal	497			645			685			224			482			484
State	(31		)	40			48			17			21			13
Total deferred expense	466			685			733			241			503			497
Amortization of deferred investment tax credits	(1		)	(1		)	(2		)	(1		)	(1		)	(1		)
Total income tax expense	$	892		$	811		$	778		$	659		$	653		$	540

(1) In 2012, Dominion’s current federal income tax expense for continuing and discontinued operations includes a $195 million benefit related to a carryback of its 2012 net operating loss. In 2011, Dominion’s deferred federal income tax expense includes the recognition of a $346 million benefit, including $51 million related to discontinued operations, for its 2011 net operating loss expected to be used to reduce taxable income in future years.

(2) In 2011, Virginia Power’s deferred federal income tax expense includes a $54 million benefit related to a portion of its 2011 net operating loss that is expected to be used in future years. Also, Virginia Power’s current federal income tax expense reflects the amounts of its 2011 net 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,	2013		2012		2011		2013		2012		2011
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	2.1		4.2		1.9		3.1		3.9		4.4
Valuation allowances	(0.1	)	(0.7	)	—		—		—		—
Investment and production tax credits	(2.4	)	(0.5	)	(0.6	)	(0.2	)	—		—
AFUDC - equity	(0.6	)	(0.9	)	(0.6	)	(0.8	)	(0.9	)	(0.8	)
Employee stock ownership plan deduction	(0.6	)	(0.7	)	(0.6	)	—		—		—
Other, net	(0.4	)	(0.6	)	(0.7	)	(0.4	)	0.3		1.1
Effective tax rate	33.0	%	35.8	%	34.4	%	36.7	%	38.3	%	39.7	%

Dominion's effective tax rate in 2012 reflects a $20 million reduction of a valuation allowance related to state operating loss carryforwards attributable to Fairless. After considering the results of Fairless’ operations in recent years and a forecast of future operating results reflecting Dominion’s planned purchase of the facility, Dominion concluded that it was more likely than not that the tax benefit of the operating losses would be realized. Dominion acquired Fairless in 2013 and will continue to evaluate the likelihood of realizing these tax benefits on a quarterly basis.

The Companies' deferred income taxes consist of the following:

	Dominion						Virginia Power
At December 31,	2013			2012			2013			2012
(millions)
Deferred income taxes:
Total deferred income tax assets	$	2,142		$	2,505		$	462		$	466
Total deferred income tax liabilities	8,463			7,716			4,498			4,238
Total net deferred income tax liabilities	$	6,321		$	5,211		$	4,036		$	3,772
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	5,383		$	4,601		$	3,628		$	3,394
Nuclear decommissioning	1,136			994			441			407
Deferred state income taxes	606			474			285			265
Federal benefit of deferred state income taxes	(212		)	(166		)	(100		)	(93		)
Deferred fuel, purchased energy and gas costs	(33		)	3			(50		)	(16		)
Pension benefits	435			231			(52		)	(17		)
Other postretirement benefits	(78		)	(171		)	(3		)	(7		)
Loss and credit carryforwards	(797		)	(656		)	(106		)	(77		)
Valuation allowances	69			93			—			—
Partnership basis differences	125			174			—			—
Other	(313		)	(366		)	(7		)	(84		)
Total net deferred income tax liabilities	$	6,321		$	5,211		$	4,036		$	3,772

At December 31, 2013, Dominion had the following deductible loss and credit carryforwards:

• Federal loss carryforwards of $1.2 billion that expire if unutilized during the period 2021 through 2033;

• Federal investment tax credits of $58 million that expire if unutilized through 2033;

• Federal production and other tax credits of $45 million that expire if unutilized during the period 2031 through 2033;

• State loss carryforwards of $1.5 billion that expire if unutilized during the period 2014 through 2033. A valuation allowance on $763 million of these carryforwards has been established;

• State minimum tax credits of $133 million that do not expire; and

• State investment tax credits of $7 million that expire if unutilized through 2017.

At December 31, 2013, Virginia Power had the following deductible loss and credit carryforwards:

• Federal loss carryforwards of $282 million that expire if unutilized during the period 2031 through 2033;

• Federal production and other tax credits of $5 million that expire if unutilized during the period 2031 through 2033; and

• State loss carryforwards of $2 million that expire if unutilized during the period 2031 through 2033.

A reconciliation of changes in the Companies' unrecognized tax benefits follows:

	Dominion									Virginia Power
	2013			2012			2011			2013			2012			2011
(millions)
Balance at January 1	$	293		$	347		$	307		$	57		$	114		$	117
Increases-prior period positions	17			28			127			12			4			22
Decreases-prior period positions	(99		)	(106		)	(119		)	(42		)	(80		)	(51		)
Increases-current period positions	30			43			64			14			24			47
Decreases-current period positions	(5		)	—			(21		)	—			—			(21		)
Settlements with tax authorities	(2		)	(4		)	—			(2		)	(4		)	—
Expiration of statutes of limitations	(12		)	(15		)	(11		)	—			(1		)	—
Balance at December 31	$	222		$	293		$	347		$	39		$	57		$	114

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. For Dominion and its subsidiaries, these unrecognized tax benefits were $126 million, $167 million and $184 million at December 31, 2013, 2012 and 2011, respectively. For Dominion, the change in these unrecognized tax benefits decreased income tax expense by $29 million in 2013 and increased income tax expense by $1 million and $51 million in 2012 and 2011, respectively. For Virginia Power, these unrecognized tax benefits were $8 million, $13 million and $20 million at December 31, 2013, 2012 and 2011, respectively. For Virginia Power, the change in these unrecognized tax benefits increased income tax expense by $4 million, $1 million and $6 million in 2013, 2012 and 2011, respectively.

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 one that was subsequently settled in 2012.

The IRS examination of tax years 2008, 2009 and 2010 began in the first quarter of 2012 and was later expanded to include the examination of the 2011 tax year. The audit concluded in late 2013, resulting in a payment of $46 million. However, the amount of a refund previously received by Dominion for its carryback of 2008 losses to 2007 was adjusted. The loss carryback, as adjusted, has been submitted to the Joint Committee for review. Dominion anticipates resolution of this matter early in 2014 with no further adjustments. Accordingly, except for 2007 and 2008, the earliest tax year remaining open for examination of Dominion’s federal tax returns is 2012.

Effective for its 2014 tax year, Dominion has been accepted into the CAP. The CAP is a method of identifying and resolving tax issues through open, cooperative, and transparent interaction between the IRS and taxpayers prior to the filing of a return. Through the CAP, Dominion will have the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions accepted by the IRS. Under a Pre-CAP plan, the IRS audit of tax years 2012 and 2013 will begin in early 2014.

With the audit protection afforded tax accounting method changes implemented under the September 2013 IRS regulations, settlement negotiations and expiration of statutes of limitations, it is reasonably possible that unrecognized tax benefits could decrease in 2014 by up to $115 million for Dominion and up to $25 million for Virginia Power. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by up to $65 million for Dominion and $7 million for Virginia Power.

Otherwise, with regard to 2013 and prior years, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2014.

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	2010
Connecticut	2010
Massachusetts	2008
Virginia(1)	2010
West Virginia	2010

(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

Details of income tax expense for discontinued operations were as follows:

	Dominion
Year Ended December 31,	2013		2012		2011
(millions)
Current:
Federal	(274	)	(248	)	(41	)
State	(41	)	(6	)	(17	)
Total current benefit	(315	)	(254	)	(58	)
Deferred:
Federal	232		(368	)	10
State	40		(70	)	15
Total deferred expense (benefit)	272		(438	)	25
Total income tax benefit	(43	)	(692	)	(33	)

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

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.

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Significant Accounting Policies (Depreciation Rates and Estimated Useful Life) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Generation
Depreciation rates	2.71%	2.62%	2.68%
Generation | Virginia Electric and Power Company
Depreciation rates	2.71%	2.62%	2.68%
Transmission
Depreciation rates	2.36%	2.17%	2.26%
Transmission | Virginia Electric and Power Company
Depreciation rates	2.28%	1.98%	2.03%
Distribution
Depreciation rates	3.13%	3.17%	3.19%
Distribution | Virginia Electric and Power Company
Depreciation rates	3.33%	3.32%	3.33%
Storage
Depreciation rates	2.43%	2.59%	2.64%
Gas gathering and processing
Depreciation rates	2.39%	2.49%	2.52%
General and other
Depreciation rates	3.82%	4.55%	4.66%
General and other | Virginia Electric and Power Company
Depreciation rates	3.51%	4.32%	4.38%
Merchant generation-nuclear
Property, Plant and Equipment, Useful Life	44 years
Minimum | General and other
Property, Plant and Equipment, Useful Life	5 years
Minimum | Merchant generation-other
Property, Plant and Equipment, Useful Life	15 years
Maximum | General and other
Property, Plant and Equipment, Useful Life	59 years
Maximum | Merchant generation-other
Property, Plant and Equipment, Useful Life	36 years

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Preferred Stock (Narrative) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
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

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Dispositions

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Dispositions

DISPOSITIONS

Sale of Illinois Gas Contracts

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

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

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

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

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

In August 2013, Dominion completed the sale and received proceeds of approximately $465 million, net of transaction costs. The sale resulted in a $35 million ($25 million after-tax) gain attributable to its equity method investment in Elwood, which is included in other income in Dominion's Consolidated Statement of Income, which was partially offset by a $17 million ($18 million after-tax) loss attributable to Brayton Point and Kincaid, which includes a $16 million write-off of goodwill and is reflected in loss from discontinued operations in Dominion's Consolidated Statement of Income. See Note 6 for other impairments related to these power stations.

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

Year Ended December 31,	2013				2012				2011
(millions)
Operating revenue	$	304			$	258			$	380
Loss before income taxes	(135		)	(1)	(1,768		)	(2)	(57		)

(1) Includes $64 million of charges related to the defeasance of Brayton Point debt and the early redemption of Kincaid debt in 2013. See Note 17 for more information.

(2) Includes a long-lived asset impairment charge of $1.6 billion.

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. Also 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 reported as discontinued operations in Dominion's Consolidated Statements of Income:

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

(1) Includes long-lived asset impairment charges of $55 million in 2011.

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Operating Revenue

12 Months Ended

Dec. 31, 2013

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,	2013		2012		2011
(millions)
Dominion
Electric sales:
Regulated	$	7,193	$	7,102	$	7,114
Nonregulated	2,511		2,483		2,721
Gas sales:
Regulated	323		250		287
Nonregulated	930		1,071		1,634
Gas transportation and storage	1,535		1,401		1,506
Other	628		528		503
Total operating revenue	$	13,120	$	12,835	$	13,765
Virginia Power
Regulated electric sales	$	7,193	$	7,102	$	7,114
Other	102		124		132
Total operating revenue	$	7,295	$	7,226	$	7,246

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Commitments and Contingencies (Subsidiary Guarantees) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Guarantor Obligations [Line Items]
Stated Limit	$ 4,421
Value	606	[1]
Debt
Guarantor Obligations [Line Items]
Stated Limit	27	[2]
Value	27	[1],[2]
Commodity transactions
Guarantor Obligations [Line Items]
Stated Limit	3,158	[2]
Value	403	[1],[2]
Nuclear obligations
Guarantor Obligations [Line Items]
Stated Limit	232	[3]
Value	68	[1],[3]
Other
Guarantor Obligations [Line Items]
Stated Limit	669	[4]
Value	108	[1],[4]
Cove Point | Nuclear obligations
Guarantor Obligations [Line Items]
Stated Limit	335	[5]
Value	0	[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, 2013 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

[2] Guarantee of debt of a DEI subsidiary. In the event of default by the subsidiary, Dominion would be obligated to repay such amounts.

[3] Guarantees related to 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.

[4] 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.

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

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Fair Value Measurements

12 Months Ended

Dec. 31, 2013

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 daily mark-to-market valuations for the Companies' derivative transactions using computer-based statistical models. 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 warehouse databases. The majority of forward prices are automatically uploaded into the data warehouse databases 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 mark-to-market valuations. During this meeting, the changes in mark-to-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

• Price correlation

• Mean reversion

• Volumes

• Commodity location

• Load shaping

• Usage factors

• 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 (for alternative investments and common/collective trust funds)

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, common/collective trust 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, mean reversion speeds, the original sales prices, and volumes. For Level 3 fair value measurements, the forward market prices, the implied price volatilities, price correlations, load shaping, mean reversion speeds, and usage factors are considered unobservable. The unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.

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

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range		Weighted Average(1)
At December 31, 2013
Assets:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	14	Discounted Cash Flow	Market Price (per Dth)	(5)	(2) - 5		2
FTRs (3)	2		Discounted Cash Flow	Market Price (per MWh)	(5)	(1) - 5		—
Liquids(4)	6		Discounted Cash Flow	Market Price (per Gal)	(5)	1 - 3		1
Physical and Financial Options:
Natural Gas(2)	4		Option Model	Market Price (per Dth)	(5)	3 - 5		4
				Price Volatility	(6)	14% - 36%		20	%
				Price Correlation	(7)	(9%) - 100%		36	%
				Mean Reversion	(8)	.01 - 1		.53
Full Requirements Contracts:
Electricity	6		Discounted Cash Flow	Market Price (per MWh)	(5)	10 - 406	(11)	42
				Load Shaping	(9)	0% - 10%		7	%
				Usage Factor	(10)	11% - 29%		16	%
Total assets	$	32
Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	19	Discounted Cash Flow	Market Price (per Dth)	(5)	(2) - 30		1
Electricity	1		Discounted Cash Flow	Market Price (per MWh)	(5)	28 - 240	(11)	39
FTRs(3)	9		Discounted Cash Flow	Market Price (per MWh)	(5)	(1) - 5		1
Liquids(4)	11		Discounted Cash Flow	Market Price (per Gal)	(5)	1 - 3		1
Physical and Financial Options:
Natural Gas(2)	8		Option Model	Market Price (per Dth)	(5)	3 - 11		7
				Price Volatility	(6)	14% - 36%		20	%
				Price Correlation	(7)	(9%) - 100%		36	%
				Mean Reversion	(8)	.01-1		.53
Total liabilities	$	48

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Includes NGLs.

(5) Represents market prices beyond defined terms for Levels 1 and 2.

(6) Represents volatilities unrepresented in published markets.

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

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

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

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

(11) 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 Shaping	Sell(1)	Increase (decrease)	Loss (gain)
Usage Factor	Sell(2)	Increase (decrease)	Gain (loss)
Mean Reversion	Buy	Increase (decrease)	Loss (gain)
Mean Reversion	Sell	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

Natural Gas Facilities

In June 2013, Dominion purchased certain natural gas infrastructure facilities that were previously leased from third parties. The purchase price was based on terms in the lease, which exceeded current market pricing. As a result of the purchase price and expected losses, Dominion recorded an impairment charge of $49 million ($29 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write down the long-lived assets to their estimated fair values of less than $1 million. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of the assets in this impairment test. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs, including estimates of future production and other commodity prices.

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 was 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 loss from discontinued operations 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.

See Note 3 for information regarding the sale of Brayton Point, Kincaid and Dominion's equity method investment in Elwood, including an additional impairment.

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 contracted to buy Kewaunee's generation expired in December 2013 at a time of 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. Kewaunee ceased operations and decommissioning activities commenced in May 2013.

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.

As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion used the income approach (discounted cash flows) to estimate the fair value of State Line's long-lived assets. 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.

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 Statement 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 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 to write down these emissions allowances to their estimated fair value of less than $1 million. For Dominion, the $57 million ($34 million after-tax) charge was recorded partially in other operations and maintenance expense ($43 million, $26 million after-tax) and partially in loss from discontinued operations ($14 million, $8 million after-tax) in its Consolidated Statement of Income. For Virginia Power, the $43 million ($26 million after-tax) charge was recorded in other operations and maintenance expense in its Consolidated Statement of Income.

To estimate the value of these emissions allowances, Dominion utilized a market approach by obtaining broker quotes to validate CSAPR's impact on emissions allowance prices. However, due to limited market activity for future SO₂ vintage year allowances, this was 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, 2013
Assets:
Derivatives:
Commodity	$	3	$	718	$	32	$	753
Interest rate	—		137		—		137
Investments(1):
Equity securities:
U.S.:
Large Cap	2,417		—		—		2,417
Other	79		—		—		79
Non-U.S.:
Large Cap	13		—		—		13
Fixed Income:
Corporate debt instruments	—		345		—		345
U.S. Treasury securities and agency debentures	415		175		—		590
State and municipal	—		343		—		343
Other	—		3		—		3
Cash equivalents and other	—		103		—		103
Restricted cash equivalents	—		8		—		8
Total assets	$	2,927	$	1,832	$	32	$	4,791
Liabilities:
Derivatives:
Commodity	$	3	$	1,051	$	48	$	1,102
Total liabilities	$	3	$	1,051	$	48	$	1,102
At December 31, 2012
Assets:
Derivatives:
Commodity	$	12	$	639	$	84	$	735
Interest rate	—		93		—		93
Investments(1):
Equity securities:
U.S.:
Large Cap	1,973		—		—		1,973
Other	59		—		—		59
Non-U.S.:
Large Cap	12		—		—		12
Fixed Income:
Corporate debt instruments	—		325		—		325
U.S. Treasury securities and agency debentures	391		152		—		543
State and municipal	—		315		—		315
Other	—		7		—		7
Cash equivalents and other	13		67		—		80
Restricted cash equivalents	—		33		—		33
Total assets	$	2,460	$	1,631	$	84	$	4,175
Liabilities:
Derivatives:
Commodity	$	8	$	528	$	59	$	595
Interest rate	—		66		—		66
Total liabilities	$	8	$	594	$	59	$	661

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

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:

	2013			2012			2011
(millions)
Balance at January 1,	$	25		$	(71	)	$	(50	)
Total realized and unrealized gains (losses):
Included in earnings	(9		)	(15		)	(77		)
Included in other comprehensive income (loss)	1			101			14
Included in regulatory assets/liabilities	(9		)	30			(42		)
Settlements	(23		)	47			88
Transfers out of Level 3	(1		)	(67		)	(4		)
Balance at December 31,	$	(16	)	$	25		$	(71	)
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

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, 2013
Total gains (losses) included in earnings	$	11		$	(19	)	$	(1	)	$	(9	)
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	1			—			(1		)	—
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

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, 2013
Assets:
Derivatives:
Commodity	$	—	$	3	$	2	$	5
Interest rate	—		48		—		48
Investments(1):
Equity securities:
U.S.:
Large Cap	1,021		—		—		1,021
Other	36		—		—		36
Fixed Income:
Corporate debt instruments	—		191		—		191
U.S. Treasury securities and agency debentures	146		66		—		212
State and municipal	—		164		—		164
Cash equivalents and other	—		31		—		31
Restricted cash equivalents	—		8		—		8
Total assets	$	1,203	$	511	$	2	$	1,716
Liabilities:
Derivatives:
Commodity	$	—	$	3	$	9	$	12
Total Liabilities	$	—	$	3	$	9	$	12
At December 31, 2012
Assets:
Derivatives:
Commodity	$	—	$	1	$	5	$	6
Investments(1):
Equity securities:
U.S.:
Large Cap	779		—		—		779
Other	27		—		—		27
Fixed Income:
Corporate debt instruments	—		196		—		196
U.S. Treasury securities and agency debentures	168		66		—		234
State and municipal	—		118		—		118
Other	—		1		—		1
Cash equivalents and other	7		31		—		38
Restricted cash equivalents	—		10		—		10
Total assets	$	981	$	423	$	5	$	1,409
Liabilities:
Derivatives:
Commodity	$	—	$	6	$	3	$	9
Interest rate	—		25		—		25
Total Liabilities	$	—	$	31	$	3	$	34

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

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:

	2013			2012			2011
(millions)
Balance at January 1,	$	2		$	(28	)	$	14
Total realized and unrealized gains (losses):
Included in earnings	(17		)	(50		)	(45		)
Included in regulatory assets/liabilities	(9		)	30			(42		)
Settlements	17			50			45
Balance at December 31,	$	(7	)	$	2		$	(28	)

The gains and losses included in earnings in the Level 3 fair value category, including any 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, 2013, 2012 and 2011. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2013, 2012 and 2011.

Fair Value of Financial Instruments

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

At December 31,	2013				2012
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	18,396	$	19,887	$	16,841	$	19,898
Long-term debt, including securities due within one year - VIE(3)	—		—		860		864
Junior subordinated notes(3)	1,373		1,394		1,373		1,430
Remarketable subordinated notes(3)	1,080		1,192		—		—
Subsidiary preferred stock(4)	257		261		257		255
Virginia Power
Long-term debt, including securities due within one year(2)	$	8,032	$	8,897	$	6,669	$	8,270
Preferred stock(4)	257		261		257		255

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2) Carrying amount includes amounts which represent the unamortized discount and premium. At December 31, 2013, and 2012, includes the valuation of certain fair value hedges associated with Dominion's fixed rate debt, of approximately $55 million and $93 million, respectively.

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

(4) Includes deferred issuance expenses of $2 million at December 31, 2013 and 2012.

XML

Income Taxes (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Loss Carryforwards [Line Items]
Deferred tax liabilities classified as current representing cumulative adjustments from tax accounting method changes	$ 17
Operating loss carryforward		195	51
Unrecognized tax benefits that would impact effective tax rate	126	167	184
Change in unrecognized tax benefits	29	1	(51)
Decrease of unrecognized tax benefits	2	4	0
Federal
Operating Loss Carryforwards [Line Items]
Operating loss carryforward	1,200
Investment tax credit	58
Tax credits	45
Payment after conclusion of audit	46
Federal | Scenario, Forecast
Operating Loss Carryforwards [Line Items]
Decrease of unrecognized tax benefits	115
Earnings increase as a result of tax settlement	65
State
Operating Loss Carryforwards [Line Items]
Operating loss carryforward	1,500
Carryforwards valuation allowance	763
General Business | State
Operating Loss Carryforwards [Line Items]
Tax credits	133
Investment Credit That Expires In 2014 | State
Operating Loss Carryforwards [Line Items]
Tax credits	7
Fairless | State
Operating Loss Carryforwards [Line Items]
Reduction of valuation allowance		20
Virginia Electric and Power Company
Operating Loss Carryforwards [Line Items]
Unrecognized tax benefits that would impact effective tax rate	8	13	20
Change in unrecognized tax benefits	(4)	(1)	(6)
Decrease of unrecognized tax benefits	2	4	0
Virginia Electric and Power Company | Federal
Operating Loss Carryforwards [Line Items]
Operating loss carryforward	282
Tax credits	5
Virginia Electric and Power Company | Federal | Scenario, Forecast
Operating Loss Carryforwards [Line Items]
Decrease of unrecognized tax benefits	25
Earnings increase as a result of tax settlement	7
Virginia Electric and Power Company | State
Operating Loss Carryforwards [Line Items]
Operating loss carryforward	$ 2

XML

Employee Benefit Plans (Benefit Obligation in Excess of Plan Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	$ 4,978	$ 5,462
Fair value of plan assets	4,553	4,189
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	1,233	1,591
Fair value of plan assets	$ 1,158	$ 1,027

XML

Investments (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			1 Months Ended	3 Months Ended	12 Months Ended			1 Months Ended		3 Months Ended		1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Blue Racer	Sep. 30, 2013 Blue Racer	Dec. 31, 2013 Blue Racer	Dec. 31, 2012 Blue Racer	Dec. 31, 2011 Blue Racer	Jan. 31, 2014 Blue Racer Subsequent Event	Mar. 31, 2013 Blue Racer Pipelines	Dec. 31, 2013 Blue Racer Pipelines	Sep. 30, 2013 Blue Racer Pipelines	Dec. 31, 2012 Other operations and maintenance expense Blue Racer	Dec. 31, 2013 Virginia Electric and Power Company	Dec. 31, 2012 Virginia Electric and Power Company	Dec. 31, 2013 Categories of Investments, Marketable Securities, Trading Securities	Dec. 31, 2012 Categories of Investments, Marketable Securities, Trading Securities	Dec. 31, 2013 Cost method investments	Dec. 31, 2012 Cost method investments
Gain (Loss) on Investments [Line Items]
Investments held in our rabbi trusts																$ 107	$ 95	$ 10	$ 14
Equity earnings on investments	14	25	35
Company received distribution from Fowler Ridge in connection with non-recourse permanent financing	33	58	55	115		160	115	0
Carrying amount of Company's investments exceeded its shares of underlying equity	36	30
Capitalized interest during construction	28
Equity method goodwill	8
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
Cash proceeds received from sale										47	30	83
Gain from sale										25	4	75
After tax gain on sale										14	2	42
Increase in equity method investment					473
Increase in equity method investment									155
Restricted cash and cash equivalent for funding qualifying projects	$ 11	$ 37												$ 8	$ 10

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Income Taxes (Reconciliation of Income Taxes at the U.S. Statutory Federal Rate as Compared to the Income Tax Expense Recorded in Our Consolidated Statements of Income) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	2.10%	4.20%	1.90%
Valuation allowances	(0.10%)	(0.70%)	0.00%
Investment and production tax credits	(2.40%)	(0.50%)	(0.60%)
AFUDC - equity	(0.60%)	(0.90%)	(0.60%)
Employee stock ownership plan deduction	(0.60%)	(0.70%)	(0.60%)
Other, net	(0.40%)	(0.60%)	(0.70%)
Effective tax rate	33.00%	35.80%	34.40%
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	3.10%	3.90%	4.40%
Valuation allowances	0.00%	0.00%	0.00%
Investment and production tax credits	(0.20%)	0.00%	0.00%
AFUDC - equity	(0.80%)	(0.90%)	(0.80%)
Employee stock ownership plan deduction	0.00%	0.00%	0.00%
Other, net	(0.40%)	0.30%	1.10%
Effective tax rate	36.70%	38.30%	39.70%

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Asset Retirement Obligations (Changes to AROs) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
AROs, Beginning balance	$ 1,705	[1]	$ 1,398	[1]
Obligations incurred during the period	13		24
Obligations settled during the period	(68)		(13)
Revisions in estimated cash flows	(129)	[2]	242	[3]
Accretion	(86)		(77)
Other	(29)		(23)
AROs , Ending balance	1,578	[1]	1,705	[1]
Other current liabilities	94		64		15
Virginia Electric and Power Company
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
AROs, Beginning balance	705		625	[4]
Obligations incurred during the period	2		18
Obligations settled during the period	(2)		(1)
Revisions in estimated cash flows	(52)	[2]	41	[5]
Accretion	(38)		(34)
Other	(2)		(12)
AROs , Ending balance	689		705
Asset retirement obligation			$ 1

[1] Includes $15 million, $64 million and $94 million reported in other current liabilities at December 31, 2011, 2012, and 2013, respectively.

[2] Primarily reflects lower anticipated nuclear decommissioning costs.

[3] Primarily reflects the accelerated timing of the decommissioning of Kewaunee that began in 2013.

[4] Includes $1 million reported in other current liabilities.

[5] Primarily reflects the effect of higher anticipated nuclear decommissioning costs.

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Operating Revenue (Operating Revenue) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended									12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Electric sales:
Regulated										$ 7,193	$ 7,102		$ 7,114
Nonregulated										2,511	2,483		2,721
Gas sales:
Regulated										323	250		287
Nonregulated										930	1,071		1,634
Gas transportation and storage										1,535	1,401		1,506
Other										628	528		503
Total operating revenue	3,185	[1]	3,432	2,980	3,523	3,101	3,332	3,005	3,397	13,120	12,835	[2]	13,765	[2]
Virginia Electric and Power Company
Electric sales:
Regulated										7,193	7,102		7,114
Gas sales:
Other										102	124		132
Total operating revenue	$ 1,745		$ 2,059	$ 1,710	$ 1,781	$ 1,630	$ 2,086	$ 1,756	$ 1,754	$ 7,295	$ 7,226		$ 7,246

[1] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3.

[2] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

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Property, Plant and Equipment (Property, Plant and Equipment) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Utility:
Generation	$ 14,018		$ 13,707
Transmission	8,686		7,799
Distribution	11,714		11,071
Storage	2,190		2,137
Nuclear fuel	1,375		1,277
Gas gathering and processing	787		803
General and other	812		803
Other-including plant under construction	3,261		2,232
Total utility	42,843		39,829
Nonutility:
Merchant generation-nuclear	1,153		1,163
Merchant generation-other	1,328	[1]	1,289	[1]
Nuclear fuel	770		775
Other-including plant under construction	875		1,265
Total nonutility	4,126		4,492
Total property, plant and equipment	46,969		44,321
Merchant generation other, due to consolidation of VIE			957
Virginia Electric and Power Company
Utility:
Generation	14,018		13,707
Transmission	4,959		4,261
Distribution	9,103		8,701
Nuclear fuel	1,375		1,277
General and other	668		659
Other-including plant under construction	2,719		2,017
Total utility	32,842		30,622
Nonutility:
Total nonutility	6		9
Total property, plant and equipment	$ 32,848		$ 30,631

[1] 2012 amount includes $957 million due to consolidation of a VIE. See Note 15 for further information.

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Commitments and Contingencies (Environmental Matters) (Narrative) (Details) (USD $)	1 Months Ended				12 Months Ended		1 Months Ended				1 Months Ended	3 Months Ended
	Jun. 30, 2013	Feb. 28, 2013 T	Apr. 30, 2012 MW	Sep. 30, 2011 Party	Dec. 31, 2013 Site	Dec. 31, 2012 T	Jul. 31, 2011 Clean Air Act Group MW State	Dec. 31, 2013 Clean Air Act	Apr. 25, 2013 Clean Air Act	Dec. 31, 2013 Remedial options	Dec. 31, 2011 Virginia Electric and Power Company	Dec. 31, 2013 Virginia Electric and Power Company Site
Loss Contingencies [Line Items]
Charge reflecting plant balances not expected to be recovered											$ 228,000,000	$ 26,000,000
Charge reflecting plant balances not expected to be recovered, net of tax											139,000,000	16,000,000
Number of states under EPA Replacement Rule							28
Emissions of fossil fuel fired electric generating units			25				25
Number of groups of affected states							2
Estimate of possible loss								13,000,000	3,000,000
Amount of environmental mitigation projects									10,000,000
Number of parties ordered specific remedial action				22
Maximum civil penalties per day					37,500
Number of former manufactured gas plant sites					17							3
Preliminary costs for options under evaluation for the site, minimum										1,000,000
Preliminary costs for options under evaluation for the site, maximum										$ 22,000,000
Percentage Reduction In CO2 Emissions		10.00%
CO2 Emissions Cap		91,000,000				165,000,000
Percent further emission reduction goals in participating state power plant CO2 emissions					2.50%
National GHC reduction goal, percentage	17.00%
Period for consideration of CO2 emissions for biomass projects					3 years

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Related Party Transactions

12 Months Ended

Dec. 31, 2013

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, 2013 and 2012, Virginia Power's derivative liabilities with affiliates were not material.

DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. 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,	2013		2012		2011
(millions)
Commodity purchases from affiliates	$	417	$	368	$	376
Services provided by affiliates	415		399		393
Services provided to affiliates	21		19		21

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 $97 million and $243 million in short-term demand note borrowings from Dominion as of December 31, 2013 and 2012, respectively. Virginia Power's outstanding borrowings, net of repayments, under the Dominion money pool for its nonregulated subsidiaries totaled $192 million as of December 31, 2012. There were no borrowings as of December 31, 2013. Interest charges related to Virginia Power's borrowings from Dominion were immaterial for the years ended December 31, 2013, 2012 and 2011.

There were no issuances of Virginia Power's common stock to Dominion in 2013, 2012 or 2011.

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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, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]
Operating Revenue	$ 3,185	[1]	$ 3,432		$ 2,980		$ 3,523		$ 3,101		$ 3,332		$ 3,005		$ 3,397		$ 13,120		$ 12,835	[2]	$ 13,765	[2]
Income from operations	804	[1]	1,034		548		930		761		551		628		918		3,316		2,858	[2]	2,880	[2]
Net income including noncontrolling interests	435	[1]	575		208		502		(652)		215		265		501		1,720		329	[2]	1,426	[2]
Income from continuing operations	431	[1],[3]	592	[3]	272	[3]	494	[3]	372	[3]	261	[3]	290	[3]	504	[3]	1,789	[3]	1,427	[2],[3]	1,466	[2]
Income (loss) from discontinued operations	0	[1],[3]	(23)	[3]	(70)	[3]	1	[3]	(1,031)	[3]	(52)	[3]	(32)	[3]	(10)	[3]	(92)	[3]	(1,125)	[3]
Net income (loss) attributable to Dominion	431	[1]	569		202		495		(659)		209		258		494		1,697		302	[2]	1,408	[2]
Income from continuing operations - basic (in dollars per share)	$ 0.74	[1],[3]	$ 1.02	[3]	$ 0.47	[3]	$ 0.86	[3]	$ 0.65	[3]	$ 0.45	[3]	$ 0.51	[3]	$ 0.88	[3]	$ 3.09	[3]	$ 2.49	[2],[3]	$ 2.56	[2]
Income (loss) from discontinued operations - basic (in dollars per share)	$ 0.00	[1],[3]	$ (0.04)	[3]	$ (0.12)	[3]	$ 0.00	[3]	$ (1.80)	[3]	$ (0.09)	[3]	$ (0.06)	[3]	$ (0.02)	[3]	$ (0.16)	[3]	$ (1.96)	[2],[3]	$ (0.10)	[2]
Net income attributable to Dominion (in dollars per share)	$ 0.74	[1]	$ 0.98		$ 0.35		$ 0.86		$ (1.15)		$ 0.36		$ 0.45		$ 0.86		$ 2.93		$ 0.53	[2]	$ 2.46	[2]
Income from continuing operations - diluted (in dollars per share)	$ 0.74	[1],[3]	$ 1.02	[3]	$ 0.47	[3]	$ 0.86	[3]	$ 0.64	[3]	$ 0.45	[3]	$ 0.51	[3]	$ 0.88	[3]	$ 3.09	[3]	$ 2.49	[2],[3]	$ 2.55	[2]
Income (loss) from discontinued operations - diluted (in dollars per share)	$ 0.00	[1],[3]	$ (0.04)	[3]	$ (0.12)	[3]	$ 0.00	[3]	$ (1.79)	[3]	$ (0.09)	[3]	$ (0.06)	[3]	$ (0.02)	[3]	$ (0.16)	[3]	$ (1.96)	[2],[3]	$ (0.10)	[2]
Net income attributable to Dominion - diluted (in dollars per share)	$ 0.74	[1]	$ 0.98		$ 0.35		$ 0.86		$ (1.15)		$ 0.36		$ 0.45		$ 0.86		$ 2.93		$ 0.53	[2]	$ 2.45	[2]
Dividends declared per common share	$ 0.5625	[1]	$ 0.5625		$ 0.5625		$ 0.5625		$ 0.5275		$ 0.5275		$ 0.5275		$ 0.5275		$ 2.25		$ 2.11	[2]	$ 1.97	[2]
Virginia Electric and Power Company
Condensed Financial Statements, Captions [Line Items]
Operating Revenue	1,745		2,059		1,710		1,781		1,630		2,086		1,756		1,754		7,295		7,226		7,246
Income from operations	408		679		463		530		417		746		361		468		2,080		1,992		1,605
Net income (loss) attributable to Dominion	199		387		265		287		220		415		172		243		1,138		1,050		822
Balance available for common stock	$ 194		$ 383		$ 261		$ 283		$ 216		$ 411		$ 168		$ 239		$ 1,121		$ 1,034		$ 805
Maximum
Condensed Financial Statements, Captions [Line Items]
Share Price	$ 67.97		$ 64.04		$ 61.85		$ 58.25		$ 53.89		$ 55.62		$ 54.69		$ 53.68		$ 67.97		$ 53.89
Common stock market value (high)																	$ 67.97		$ 55.62
Minimum
Condensed Financial Statements, Captions [Line Items]
Share Price	$ 61.36		$ 55.51		$ 53.79		$ 51.92		$ 48.94		$ 52.15		$ 49.87		$ 48.87		$ 61.36		$ 48.94
Common stock market value (low)																	$ 51.92		$ 48.87

[1] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3.

[2] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

[3] Amounts attributable to Dominion's common shareholders.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2013

Long-term Debt, Unclassified [Abstract]

Long term Debt

At December 31,	2013 Weighted- average Coupon(1)		2013			2012
(millions, except percentages)
Virginia Electric and Power Company:
Unsecured Senior Notes:
1.2% to 8.625%, due 2013 to 2018	5.09	%	$	2,138		$	2,306
2.75% to 8.875%, due 2019 to 2043	5.25	%	4,993			3,408
Tax-Exempt Financings(2):
Variable rates, due 2016 to 2041	0.98	%	606			454
1.5% to 5.6%, due 2022 to 2040	3.16	%	306			508
Virginia Electric and Power Company total principal			$	8,043		$	6,676
Securities due within one year	4.10	%	(58		)	(418		)
Unamortized discount and premium, net			(11		)	(7		)
Virginia Electric and Power Company total long-term debt			$	7,974		$	6,251
Dominion Resources, Inc.:
Unsecured Senior Notes:
Variable rates, due 2013 and 2014	0.37	%	$	400		$	400
1.4% to 7.195%, due 2013 to 2018	4.03	%	3,291			3,541
2.75% to 8.875%, due 2019 to 2042(3)	5.64	%	4,599			4,599
Unsecured Convertible Senior Notes, 2.125%, due 2023(4)			43			82
Tax-Exempt Financing, variable rate, due 2041(5)	1.12	%	75			—
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031	8.40	%	10			268
Enhanced Junior Subordinated Notes:
7.5% and 8.375%, due 2064 and 2066	8.11	%	985			985
Variable rate, due 2066	2.58	%	380			380
Remarketable Subordinated Notes, 1.07% and 1.18%, due 2019 and 2021	1.13	%	1,100			—
Unsecured Debentures and Senior Notes(6):
5.0% and 6.625%, due 2013 and 2014	5.00	%	600			622
6.8% and 6.875%, due 2026 and 2027	6.81	%	89			89
Dominion Gas Holdings, LLC:
Unsecured Senior Notes, 1.05% to 4.8%, due 2016 to 2043	3.13	%	1,200			—
Dominion Energy, Inc.:
Secured Senior Notes:
5.03% to 5.78%, due 2013(7)			—			842
7.33%, due 2020(8)			—			145
Tax-Exempt Financings:
2.25% to 5.75%, due 2033 to 2042(9)	2.38	%	27			284
Variable rate, due 2041(5)			—			75
Virginia Electric and Power Company total principal (from above)			8,043			6,676
Dominion Resources, Inc. total principal			$	20,842		$	18,988
Fair value hedge valuation(10)			55			93
Securities due within one year(11)	2.95	%	(1,519		)	(2,223		)
Unamortized discount and premium, net			(48		)	(7		)
Dominion Resources, Inc. total long-term debt			$	19,330		$	16,851

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2013.

(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 2018.

(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, 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) Debt issued by the MDFA on behalf of Brayton Point. In connection with the sale of Brayton Point, the sole obligor under the bonds was changed from Brayton Point to Dominion in June 2013.

(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 of unamortized premium in 2012. The debt was non-recourse to Dominion and was secured by Juniper's assets. Dominion's purchase of Fairless in August 2013 resulted in the removal of the debt from Dominion's Consolidated Balance Sheet. See Note 15 for additional information.

(8) Represented debt associated with Kincaid. The debt was non-recourse to Dominion and was secured by the facility's assets and revenue. In connection with the sale of Kincaid, the notes were redeemed in May 2013 for approximately $185 million, including a make-whole premium and accrued interest.

(9) In 2012 included debt issued by the MDFA on behalf of Brayton Point. In connection with the sale of Brayton Point, three series of bonds totaling approximately $257 million were defeased in June 2013. In June 2013, Brayton Point delivered approximately $284 million to fund an irrevocable trust for the purpose of paying maturing principal and interest due through and including the earliest redemption dates of the bonds in 2016 and 2019.

(10) Represents the valuation of certain fair value hedges associated with Dominion's fixed rate debt.

(11) Includes $14 million fair value hedge valuation in 2013 and $23 million of net unamortized premium and fair value hedge valuation in 2012.

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, 2013, were as follows:

	2014			2015			2016			2017			2018			Thereafter			Total
(millions, except percentages)
Virginia Power	$	58		$	211		$	476		$	679		$	850		$	5,769		$	8,043
Weighted-average Coupon	4.10		%	5.39		%	5.25		%	5.44		%	4.17		%	4.78		%
Dominion
Unsecured Senior Notes	$	1,465		$	960		$	1,752		$	1,303		$	1,350		$	10,523		$	17,353
Tax-Exempt Financings	40			—			19			75			—			880			1,014
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts	—			—			—			—			—			10			10
Enhanced Junior Subordinated Notes	—			—			—			—			—			1,365			1,365
Remarketable Subordinated Notes	—			—			—			—			—			1,100			1,100
Total	$	1,505		$	960		$	1,771		$	1,378		$	1,350		$	13,878		$	20,842
Weighted-average Coupon	2.95		%	4.45		%	3.51		%	4.55		%	4.99		%	4.90		%

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, 2013:

Date Established	Capital Trust	Units	Rate		Capital Securities Amount		Common Securities Amount
		(thousands)			(millions)
January 2001	Dominion Resources Capital Trust III(1)	10	8.4	%	$	10	$	0.3

(1) $10 million-Dominion Resources, Inc. 8.4% Debentures due 1/15/2031 were held as assets by the capital trust.

Schedule of Capital Units

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

Issuance Date	Units Issued	Total Net Proceeds		Total Long-term Debt		RSN Annual Interest Rate		Stock Purchase Contract Annual Rate		Stock Purchase Contract Liability(1)		Stock Purchase Settlement Date	RSN Maturity Date
(millions, except interest rates)
6/7/2013	11	$	533.5	$	550.0	1.070	%	5.055	%	$	76.7	4/1/2016	4/1/2021
6/7/2013	11	$	553.5	$	550.0	1.180	%	4.820	%	$	79.3	7/1/2016	7/1/2019

(1) Payments of $17 million were made in 2013. The stock purchase contract liability was $139 million at December 31, 2013.

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Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2013

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(1)		Total
(millions)
Balance at December 31, 2011(2)	$	1,503		(3)	$	712			$	926	(3)	$	—	$	3,141
Asset disposition adjustment	—				(11		)	(5)	—			—		(11		)
Balance at December 31, 2012(2)	$	1,503			$	701			$	926		$	—	$	3,130
Asset disposition adjustment	(19		)	(4)	(25		)	(5)	—			—		(44		)
Balance at December 31, 2013(2)	$	1,484			$	676			$	926		$	—	$	3,086

(1) Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.

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

(3) Recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

(4) See Note 3 for a discussion of Dominion's dispositions and related goodwill write-offs.

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

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 $72 million, $82 million and $78 million for 2013, 2012 and 2011, respectively. In 2013, Dominion acquired $81 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of approximately 10 years. Amortization expense for Virginia Power's intangible assets was $22 million for 2013, 2012, and 2011. In 2013, Virginia Power acquired $14 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 5 years. The components of intangible assets are as follows:

At December 31,	2013				2012
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion
Software, licenses and other	$	867	$	308	$	859	$	327
Emissions allowances	3		2		5		1
Total	$	870	$	310	$	864	$	328
Virginia Power
Software, licenses and other	$	271	$	78	$	303	$	122
Total	$	271	$	78	$	303	$	122

Annual amortization expense for these intangible assets is estimated to be as follows:

	2014		2015		2016		2017		2018
(millions)
Dominion	$	69	$	59	$	50	$	40	$	29
Virginia Power	$	21	$	15	$	12	$	9	$	5

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Shareholders' Equity (Schedule of Reclassifications out of Accumulated Other Comprehensive Income) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended									12 Months Ended
	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating Revenue	$ 3,185	[1]	$ 3,432	$ 2,980	$ 3,523	$ 3,101	$ 3,332	$ 3,005	$ 3,397	$ 13,120		$ 12,835	[2]	$ 13,765	[2]
Purchased gas										1,331		1,177	[2]	1,764	[2]
Electric fuel and other energy-related purchases										3,885		3,645	[2]	3,942	[2]
Interest and related charges										877		816	[2]	796	[2]
Income from continuing operations including noncontrolling interests before income taxes										2,704		2,265	[2]	2,262	[2]
Income Tax Expense (Benefit)										(892)	[3]	(811)	[2],[3]	(778)	[2],[3]
Income from continuing operations including noncontrolling interests										1,812		1,454	[2]	1,484	[2]
Other income										265		223	[2]	178	[2]
Impairment										8		14		48
Deferred gains and losses on derivatives-hedging activities | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income from continuing operations including noncontrolling interests before income taxes										130
Income Tax Expense (Benefit)										(53)
Income from continuing operations including noncontrolling interests										77
Unrealized gains and losses on investment securities | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income from continuing operations including noncontrolling interests before income taxes										(90)
Income Tax Expense (Benefit)										35
Income from continuing operations including noncontrolling interests										(55)
Other income										(98)
Impairment										8
Unrecognized pension and other postretirement benefit costs | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income from continuing operations including noncontrolling interests before income taxes										94
Income Tax Expense (Benefit)										(39)
Income from continuing operations including noncontrolling interests										55
Prior-service costs (credits)										(8)
Actuarial losses										102
Commodity | Deferred gains and losses on derivatives-hedging activities | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating Revenue										58
Purchased gas										47
Electric fuel and other energy-related purchases										10
Interest rate | Deferred gains and losses on derivatives-hedging activities | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest and related charges										15
Virginia Electric and Power Company
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating Revenue	1,745		2,059	1,710	1,781	1,630	2,086	1,756	1,754	7,295		7,226		7,246
Electric fuel and other energy-related purchases										2,304		2,368		2,506
Interest and related charges										369		385		331
Income from continuing operations including noncontrolling interests before income taxes										1,797		1,703		1,362
Income Tax Expense (Benefit)										(659)	[4]	(653)	[4]	(540)	[4]
Other income										86		96		88
Impairment										1		1		4
Virginia Electric and Power Company | Unrealized gains and losses on investment securities | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income from continuing operations including noncontrolling interests before income taxes										(5)
Income Tax Expense (Benefit)										2
Income from continuing operations including noncontrolling interests										(3)
Other income										(6)
Impairment										$ 1

[1] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3.

[2] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

[3] In 2012, Dominion’s current federal income tax expense for continuing and discontinued operations includes a $195 million benefit related to a carryback of its 2012 net operating loss. In 2011, Dominion’s deferred federal income tax expense includes the recognition of a $346 million benefit, including $51 million related to discontinued operations, for its 2011 net operating loss expected to be used to reduce taxable income in future years.

[4] In 2011, Virginia Power’s deferred federal income tax expense includes a $54 million benefit related to a portion of its 2011 net operating loss that is expected to be used in future years. Also, Virginia Power’s current federal income tax expense reflects the amounts of its 2011 net operating losses realized through its participation in a tax sharing agreement with Dominion and its subsidiaries.

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Short-Term Debt And Credit Agreements

12 Months Ended

Dec. 31, 2013

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:

	Facility Limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Capacity Available
(millions)
At December 31, 2013
Joint revolving credit facility(1)	$	3,000	$	1,927		$	—	$	1,073
Joint revolving credit facility(2)	500		—			11		489
Total	$	3,500	$	1,927	(3)	$	11	$	1,562
At December 31, 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

(1) Effective September 2013, the maturity date was extended from September 2017 to September 2018. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.

(2) Effective September 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

(3) The weighted-average interest rates of the outstanding commercial paper supported by Dominion's credit facilities were 0.33% and 0.49% at December 31, 2013 and 2012, 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:

	Facility Sub-limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Sub-limit Capacity Available
(millions)
At December 31, 2013
Joint revolving credit facility(1)	$	1,000	$	842		$	—	$	158
Joint revolving credit facility(2)	250		—			1		249
Total	$	1,250	$	842	(3)	$	1	$	407
At December 31, 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

(1) Effective September 2013, the maturity date was extended from September 2017 to September 2018. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power's current sub-limit under this credit facility can be increased or decreased multiple times per year.

(2) Effective September 2013, the maturity date for $400 million of the $500 million committed capacity was extended from September 2017 to September 2018. Also effective September 2013, the maturity date for the remaining $100 million was extended from September 2016 to September 2018. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power's 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 0.33% and 0.47% at December 31, 2013 and 2012, respectively.

In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility. Effective September 2013, the maturity date was extended from September 2017 to September 2018. As of December 31, 2013, this facility supports approximately $119 million of certain variable rate tax-exempt financings of Virginia Power.

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Goodwill and Intangible Assets (Goodwill) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 3,130	[1]	$ 3,141	[1]
Asset disposition adjustment	(44)		(11)
Goodwill, Ending Balance	3,086	[1]	3,130	[1]
Dominion Generation
Goodwill [Roll Forward]
Goodwill, Beginning Balance	1,503	[1],[2]	1,503	[1],[2]
Asset disposition adjustment	(19)	[3]	0
Goodwill, Ending Balance	1,484	[1]	1,503	[1],[2]
Dominion Energy
Goodwill [Roll Forward]
Goodwill, Beginning Balance	701	[1]	712	[1]
Asset disposition adjustment	(25)	[4]	(11)	[4]
Goodwill, Ending Balance	676	[1]	701	[1]
DVP
Goodwill [Roll Forward]
Goodwill, Beginning Balance	926	[1]	926	[1],[2]
Asset disposition adjustment	0		0
Goodwill, Ending Balance	926	[1]	926	[1]
Corporate and Other
Goodwill [Roll Forward]
Goodwill, Beginning Balance	0	[1],[5]	0	[1],[5]
Asset disposition adjustment	0	[5]	0	[5]
Goodwill, Ending Balance	$ 0	[1],[5]	$ 0	[1],[5]

[1] Goodwill amounts do not contain any accumulated impairment losses.

[2] Recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

[3] See Note 3 for a discussion of Dominion's dispositions and related goodwill write-offs.

[4] Related to assets sold or contributed to Blue Racer.

[5] Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation [Abstract]

Changes to Asset Retirement Obligations

The changes to AROs during 2012 and 2013 were as follows:

	Amount
(millions)
Dominion
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(2)	242
Accretion	77
Other	(23		)
AROs at December 31, 2012(1)	$	1,705
Obligations incurred during the period	13
Obligations settled during the period	(68		)
Revisions in estimated cash flows(3)	(129		)
Accretion	86
Other	(29		)
AROs at December 31, 2013(1)	$	1,578
Virginia Power
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
Obligations incurred during the period	2
Obligations settled during the period	(2		)
Revisions in estimated cash flows(3)	(52		)
Accretion	38
Other	(2		)
AROs at December 31, 2013	$	689

(1) Includes $15 million, $64 million and $94 million reported in other current liabilities at December 31, 2011, 2012, and 2013, respectively.

(2) Primarily reflects the accelerated timing of the decommissioning of Kewaunee that began in 2013.

(3) Primarily reflects lower anticipated nuclear decommissioning costs.

(4) Includes $1 million reported in other current liabilities.

(5) Primarily reflects the effect of higher anticipated nuclear decommissioning costs.

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Long-Term Debt (Narrative) (Details) (USD $)	1 Months Ended		12 Months Ended	1 Months Ended	12 Months Ended	1 Months Ended						1 Months Ended					1 Months Ended									12 Months Ended					1 Months Ended
	Jan. 31, 2013	Sep. 30, 2011	Dec. 31, 2013	Sep. 30, 2013 Iroquois Gas Transmission System, L.P.	Dec. 31, 2013 Scenario, Forecast	Jul. 31, 2016 Scenario, Forecast Minimum	Apr. 30, 2016 Scenario, Forecast Minimum	Jul. 31, 2016 Scenario, Forecast Maximum	Apr. 30, 2016 Scenario, Forecast Maximum	Jun. 30, 2013 Capital Unit, Class A	Sep. 30, 2013 Capital Unit, Class A	Jun. 30, 2013 Capital Unit, Class B	Sep. 30, 2013 Capital Unit, Class B	Dec. 31, 2013 Common Stock	Jul. 01, 2006 June 2006 hybrids	Jun. 30, 2006 June 2006 hybrids	Feb. 28, 2012 September 2006 hybrids	Jun. 30, 2012 September 2006 hybrids	Mar. 31, 2012 September 2006 hybrids	Dec. 31, 2011 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, 2013 Convertible Debt	Dec. 31, 2013 Enhanced Junior Subordinated Notes	Dec. 31, 2012 Enhanced Junior Subordinated Notes	Dec. 31, 2011 Enhanced Junior Subordinated Notes	Oct. 22, 2013 Senior Notes Unsecured Senior Notes	Jan. 31, 2013 7.83% Debentures due 12/1/2027	Jan. 31, 2014 Subsequent Event	Feb. 26, 2014 Subsequent Event	Feb. 28, 2014 Subsequent Event Senior Notes Senior Notes Maturing in 2024	Feb. 28, 2014 Subsequent Event Senior Notes Senior Notes Maturing in 2044
Debt Instrument [Line Items]
Outstanding contingent convertible senior notes			$ 43,000,000
Conversion rate adjustment (shares)			$ 29.8780
Principal Amount of Senior Notes																									$ 1,000
Conversion price (per share)																									$ 33.47
Shares of stock issued if all converted					600,000
Dividends declared payable (in dollars per share)																															$ 60.00
Conversion rate (shares)																																$ 29.9961
Average trading price principal amount of the senior notes			120.00%
Minimum consecutive trading days			20 days
Maximum consecutive trading days			30 days
Convertible senior notes converted by holders			39,000,000
Shares issued in excess of principal amounts related to converted securities			28,000,000
Redemption rate			100.00%
Noncontrolling interest, ownership percentage by parent			100.00%
Beneficial ownership percentage			97.00%
Beneficial ownership interest			3.00%
Percentage in capital trust assets			100.00%
Junior subordinated notes																300,000,000						500,000,000		685,000,000						258,000,000
RSN Annual Interest Rate															2.825%	7.50%					2.30%	6.30%	8.375%							7.83%			3.45%	4.45%
Redemption of units of Dominion Resources Capital Trust I capital securities	250,000
Dominion Resources Capital Trust I capital securities	250,000,000
Rate of Dominion Resources Capital Trust I capital securities	7.83%
Redemption price per capital security	$ 1,019.58
Interest charges																										1,000,000	21,000,000	21,000,000
Deferral			10 years
Period for consideration of proceeds (days)		180 days	365 days
Purchased and cancelled of junior subordinated notes																		2,000,000	86,000,000	16,000,000
Tender offer to purchase additional hybrids																	150,000,000
Equity units issued										550,000,000		550,000,000
Payment rate on Equity Units											6.125%		6.00%
Percentage interest on RSN issued by Dominion			5.00%
Purchase price to be paid under stock purchase contracts														$ 50
Shares to be issued under purchase contracts						8,400,000	8,400,000	9,900,000	9,900,000
Shares reserved and available for issuance			22,500,000
General partnership interest in Iroquois				24.72%
Total Long-term Debt																													$ 1,200,000,000.0				$ 350,000,000	$ 400,000,000

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [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,	2013			2012			2011			2013			2012			2011
(millions)
Current:
Federal	$	317		$	43		$	31		$	357		$	70		$	(35	)
State	110			84			16			62			81			79
Total current expense	427			127			47			419			151			44
Deferred:
Federal	497			645			685			224			482			484
State	(31		)	40			48			17			21			13
Total deferred expense	466			685			733			241			503			497
Amortization of deferred investment tax credits	(1		)	(1		)	(2		)	(1		)	(1		)	(1		)
Total income tax expense	$	892		$	811		$	778		$	659		$	653		$	540

(1) In 2012, Dominion’s current federal income tax expense for continuing and discontinued operations includes a $195 million benefit related to a carryback of its 2012 net operating loss. In 2011, Dominion’s deferred federal income tax expense includes the recognition of a $346 million benefit, including $51 million related to discontinued operations, for its 2011 net operating loss expected to be used to reduce taxable income in future years.

(2) In 2011, Virginia Power’s deferred federal income tax expense includes a $54 million benefit related to a portion of its 2011 net operating loss that is expected to be used in future years. Also, Virginia Power’s current federal income tax expense reflects the amounts of its 2011 net 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,	2013		2012		2011		2013		2012		2011
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	2.1		4.2		1.9		3.1		3.9		4.4
Valuation allowances	(0.1	)	(0.7	)	—		—		—		—
Investment and production tax credits	(2.4	)	(0.5	)	(0.6	)	(0.2	)	—		—
AFUDC - equity	(0.6	)	(0.9	)	(0.6	)	(0.8	)	(0.9	)	(0.8	)
Employee stock ownership plan deduction	(0.6	)	(0.7	)	(0.6	)	—		—		—
Other, net	(0.4	)	(0.6	)	(0.7	)	(0.4	)	0.3		1.1
Effective tax rate	33.0	%	35.8	%	34.4	%	36.7	%	38.3	%	39.7	%

The Companies deferred income taxes components

The Companies' deferred income taxes consist of the following:

	Dominion						Virginia Power
At December 31,	2013			2012			2013			2012
(millions)
Deferred income taxes:
Total deferred income tax assets	$	2,142		$	2,505		$	462		$	466
Total deferred income tax liabilities	8,463			7,716			4,498			4,238
Total net deferred income tax liabilities	$	6,321		$	5,211		$	4,036		$	3,772
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	5,383		$	4,601		$	3,628		$	3,394
Nuclear decommissioning	1,136			994			441			407
Deferred state income taxes	606			474			285			265
Federal benefit of deferred state income taxes	(212		)	(166		)	(100		)	(93		)
Deferred fuel, purchased energy and gas costs	(33		)	3			(50		)	(16		)
Pension benefits	435			231			(52		)	(17		)
Other postretirement benefits	(78		)	(171		)	(3		)	(7		)
Loss and credit carryforwards	(797		)	(656		)	(106		)	(77		)
Valuation allowances	69			93			—			—
Partnership basis differences	125			174			—			—
Other	(313		)	(366		)	(7		)	(84		)
Total net deferred income tax liabilities	$	6,321		$	5,211		$	4,036		$	3,772

Reconciliation of changes in the Companies unrecognized tax benefits

A reconciliation of changes in the Companies' unrecognized tax benefits follows:

	Dominion									Virginia Power
	2013			2012			2011			2013			2012			2011
(millions)
Balance at January 1	$	293		$	347		$	307		$	57		$	114		$	117
Increases-prior period positions	17			28			127			12			4			22
Decreases-prior period positions	(99		)	(106		)	(119		)	(42		)	(80		)	(51		)
Increases-current period positions	30			43			64			14			24			47
Decreases-current period positions	(5		)	—			(21		)	—			—			(21		)
Settlements with tax authorities	(2		)	(4		)	—			(2		)	(4		)	—
Expiration of statutes of limitations	(12		)	(15		)	(11		)	—			(1		)	—
Balance at December 31	$	222		$	293		$	347		$	39		$	57		$	114

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	2010
Connecticut	2010
Massachusetts	2008
Virginia(1)	2010
West Virginia	2010

(1) Virginia is the only state considered major for Virginia Power's operations.

Schedule of Components of Income Tax Expense (Benefit) from Discontinued Operations [Table Text Block]

Details of income tax expense for discontinued operations were as follows:

	Dominion
Year Ended December 31,	2013		2012		2011
(millions)
Current:
Federal	(274	)	(248	)	(41	)
State	(41	)	(6	)	(17	)
Total current benefit	(315	)	(254	)	(58	)
Deferred:
Federal	232		(368	)	10
State	40		(70	)	15
Total deferred expense (benefit)	272		(438	)	25
Total income tax benefit	(43	)	(692	)	(33	)

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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, 2013
Debt Instrument [Line Items]
2014	$ 1,505
2015	960
2016	1,771
2017	1,378
2018	1,350
Thereafter	13,878
Total	20,842
Virginia Electric and Power Company
Debt Instrument [Line Items]
2014	58
2015	211
2016	476
2017	679
2018	850
Thereafter	5,769
Total	8,043
2014
Debt Instrument [Line Items]
Weighted-average Coupon	2.95%
2014 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	4.10%
2015
Debt Instrument [Line Items]
Weighted-average Coupon	4.45%
2015 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	5.39%
2016
Debt Instrument [Line Items]
Weighted-average Coupon	3.51%
2016 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	5.25%
2017
Debt Instrument [Line Items]
Weighted-average Coupon	4.55%
2017 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	5.44%
2018
Debt Instrument [Line Items]
Weighted-average Coupon	4.99%
2018 | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	4.17%
Thereafter
Debt Instrument [Line Items]
Weighted-average Coupon	4.90%
Thereafter | Virginia Electric and Power Company
Debt Instrument [Line Items]
Weighted-average Coupon	4.78%
Unsecured Senior Notes
Debt Instrument [Line Items]
2014	1,465
2015	960
2016	1,752
2017	1,303
2018	1,350
Thereafter	10,523
Total	17,353
Tax-Exempt Financings
Debt Instrument [Line Items]
2014	40
2015	0
2016	19
2017	75
2018	0
Thereafter	880
Total	1,014
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts
Debt Instrument [Line Items]
2014	0
2015	0
2016	0
2017	0
2018	0
Thereafter	10
Total	10
Enhanced Junior Subordinated Notes
Debt Instrument [Line Items]
2014	0
2015	0
2016	0
2017	0
2018	0
Thereafter	1,365
Total	1,365
Remarketable Subordinated Notes
Debt Instrument [Line Items]
2014	0
2015	0
2016	0
2017	0
2018	0
Thereafter	1,100
Total	$ 1,100

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net deferred gains (losses) on derivatives-hedging activities, tax	$ 161	$ 5	$ 48
Changes in unrealized net gains (losses) on investment securities, tax	(136)	(68)	(7)
Changes in net unrecognized pension and other postretirement benefit costs, tax	(341)	209	147
Net derivative (gains) losses-hedging activities, tax	(53)	34	28
Net realized (gains) losses on investment securities, tax	35	16	(4)
Net pension and other postretirement benefit costs, tax	(39)	(32)	(25)
Virginia Electric and Power Company
Net deferred gains (losses) on derivatives-hedging activities, tax	(3)	3	3
Changes in unrealized net gains (losses) on investment securities, tax	(13)	(7)	(1)
Net derivative (gains) losses-hedging activities, tax	0	(2)	0
Net realized (gains) losses on investment securities, tax	$ 2	$ 2	$ 0

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Investments (Selected Information Regarding Marketable Equity and Debt Securities) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Available-for-sale securities:
Proceeds from sales	$ 1,476		$ 1,356		$ 1,757
Realized gains	157	[1]	98	[1]	79	[1]
Realized losses	33	[1]	33	[1]	92	[1]
Virginia Electric and Power Company
Available-for-sale securities:
Proceeds from sales	572		626		1,030
Realized gains	52	[1]	42	[1]	34	[1]
Realized losses	$ 14	[1]	$ 11	[1]	$ 34	[1]

[1] Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2.

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2013 Virginia Electric and Power Company	Dec. 31, 2012 Virginia Electric and Power Company	Dec. 31, 2011 Virginia Electric and Power Company
Operating Activities
Net income including noncontrolling interests	$ 1,720	$ 329	[1]	$ 1,426	[1]
Net income (loss) attributable to Dominion	1,697	302	[1]	1,408	[1]	1,138	1,050	822
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Impairment of generation assets	48	2,089		283		0	0	228
Net reserves (payments) related to rate refunds	(5)	(151)		3		(5)	(151)	3
Depreciation, depletion and amortization (including nuclear fuel)	1,390	1,443		1,288		1,016	927	838
Deferred income taxes and investment tax credits	737	246		756		240	502	496
Gains on the sale of assets	(122)	(81)		0
Other adjustments	(129)	(164)		(207)		(63)	(70)	(93)
Changes in:
Accounts receivable	(98)	292		365		(124)	126	76
Affiliated accounts receivable and payable						3	(2)	(7)
Inventories	(29)	33		(185)		(19)	8	(200)
Deferred fuel and purchased gas costs, net	102	368		(3)		93	378	12
Prepayments	123	(85)		(19)		(9)	18	24
Accounts payable	50	(61)		(413)		15	19	(117)
Accrued interest, payroll and taxes	(27)	(12)		(216)		14	(22)	12
Increase (Decrease) in Margin Deposits Outstanding	(414)	45		(71)
Other operating assets and liabilities	87	(154)		(24)		30	(77)	(70)
Net cash provided by operating activities	3,433	4,137		2,983		2,329	2,706	2,024
Investing Activities
Plant construction and other property additions (including nuclear fuel)	(4,104)	(4,145)		(3,652)		(2,394)	(2,082)	(1,885)
Purchases of nuclear fuel						(139)	(206)	(205)
Purchases of securities						(603)	(638)	(1,057)
Proceeds from sales of securities						572	626	1,030
Proceeds from sales of securities	1,476	1,356		1,757
Purchases of securities	(1,493)	(1,392)		(1,824)
Proceeds from the sale of Brayton Point, Kincaid and equity method investment in Elwood	465	0		0
Proceeds from Blue Racer	33	58		55
Restricted cash equivalents	25	108		259		2	22	137
Other	13	118		139		(39)	(4)	33
Net cash used in investing activities	(3,458)	(3,840)		(3,321)		(2,601)	(2,282)	(1,947)
Financing Activities
Issuance (repayment) of short-term debt, net	(485)	598		429		(151)	98	294
Issuance of short-term notes	400	400		0
Repayment of short-term notes	(400)	0		0
Issuance (repayment) of affiliated current borrowings, net						(338)	248	85
Issuance and remarketing of long-term debt	4,135	1,500		2,320		1,835	450	235
Repayment and repurchase of long-term debt, including redemption premiums	(1,245)	(1,675)		(637)
Repayment and repurchase of long-term debt	(258)	0		0		(470)	(641)	(91)
Acquisition of Juniper noncontrolling interest in Fairless	(923)	0		0
Issuance of common stock	278	265		38
Repurchase of common stock	0	0		(601)
Common dividend payments	(1,302)	(1,209)		(1,129)		(579)	(559)	(557)
Subsidiary preferred dividend payments	(17)	(16)		(17)		(17)	(16)	(17)
Other	(90)	(14)		(25)		(20)	(5)	(2)
Net cash provided by (used in) financing activities	93	(151)		378		260	(425)	(53)
Increase in cash and cash equivalents	68	146		40		(12)	(1)	24
Cash and cash equivalents at beginning of year	248	102		62		28	29	5
Cash and cash equivalents at end of year	316	248		102		16	28	29
Supplemental Cash Flow Information
Interest and related charges, excluding capitalized amounts	852	913		920		328	376	376
Income taxes	56	(58)		166		427	225	(27)
Significant noncash investing and financing activities:
Accrued capital expenditures	375	388		328		276	242	199
Consolidation of VIE - assets at fair value	0	0		957
Consolidation of VIE - debt	$ 0	$ 0		$ 896

[1] Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3 to the Consolidated Financial Statements. EPS amounts reflect the per share impact of the recast of $1.92 and $0.06 for 2012 and 2011, respectively.

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Quarterly Financial and Common Stock Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Condensed Financial Statements, Captions [Line Items]

Quarterly Financial and Common Stock Data

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter (2)			Full Year
(millions, except per share amounts)
2013
Operating revenue	$	3,523		$	2,980		$	3,432		$	3,185		$	13,120
Income from operations	930			548			1,034			804			3,316
Net income including noncontrolling interests	502			208			575			435			1,720
Income from continuing operations(1)	494			272			592			431			1,789
Income (loss) from discontinued operations(1)	1			(70		)	(23		)	—			(92		)
Net income attributable to Dominion	495			202			569			431			1,697
Basic EPS:
Income from continuing operations(1)	0.86			0.47			1.02			0.74			3.09
Income (loss) from discontinued operations(1)	—			(0.12		)	(0.04		)	—			(0.16		)
Net income attributable to Dominion	0.86			0.35			0.98			0.74			2.93
Diluted EPS:
Income from continuing operations(1)	0.86			0.47			1.02			0.74			3.09
Income (loss) from discontinued operations(1)	—			(0.12		)	(0.04		)	—			(0.16		)
Net income attributable to Dominion	0.86			0.35			0.98			0.74			2.93
Dividends declared per share	0.5625			0.5625			0.5625			0.5625			2.25
Common stock prices (intraday high-low)	$58.25  - 51.92			$61.85  - 53.79			$64.04 - 55.51			$67.97  - 61.36			$67.97  - 51.92
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Full Year
2012
Operating revenue	$	3,397		$	3,005		$	3,332		$	3,101		$	12,835
Income from operations	918			628			551			761			2,858
Net income (loss) including noncontrolling interests	501			265			215			(652		)	329
Income from continuing operations(1)	504			290			261			372			1,427
Income (loss) from discontinued operations(1)	(10		)	(32		)	(52		)	(1,031		)	(1,125		)
Net income attributable to Dominion	494			258			209			(659		)	302
Basic EPS:
Income from continuing operations(1)	0.88			0.51			0.45			0.65			2.49
Loss from discontinued operations(1)	(0.02		)	(0.06		)	(0.09		)	(1.80		)	(1.96		)
Net income (loss) attributable to Dominion	0.86			0.45			0.36			(1.15		)	0.53
Diluted EPS:
Income from continuing operations(1)	0.88			0.51			0.45			0.64			2.49
Loss from discontinued operations(1)	(0.02		)	(0.06		)	(0.09		)	(1.79		)	(1.96		)
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

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

(2) Recast to reflect Brayton Point and Kincaid as discontinued operations as described in Note 3.

Virginia Electric and Power Company

Condensed Financial Statements, Captions [Line Items]

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)
2013
Operating revenue	$	1,781	$	1,710	$	2,059	$	1,745	$	7,295
Income from operations	530		463		679		408		2,080
Net income	287		265		387		199		1,138
Balance available for common stock	283		261		383		194		1,121
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

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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, 2013		Dec. 31, 2012		Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	$ (404)	[1]	$ (13)	[1]	$ (115)	[1]
Amount of Gain (Loss) Reclassified from AOCI to Income	(130)		94		66
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	86	[2]	(25)	[2]	(163)	[2]
Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	(481)	[1]	71	[1]	137	[1]
Amount of Gain (Loss) Reclassified from AOCI to Income	(115)		96		74
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	5	[2]	10	[2]	(20)	[2]
Commodity | Operating Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Income	(58)		188		153
Commodity | Purchased gas
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Income	(47)		(75)		(78)
Commodity | Electric fuel and other energy-related purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Income	(10)		(17)		(2)
Commodity | Purchased electric capacity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Income					1
Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	77	[1],[3]	(84)	[1],[3]	(252)	[1],[3]
Amount of Gain (Loss) Reclassified from AOCI to Income	(15)	[3]	(2)	[3]	(8)	[3]
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	81	[2],[3]	(35)	[2],[3]	(143)	[2],[3]
Virginia Electric and Power Company
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	9	[4]	(8)	[4]	(9)	[4]
Amount of Gain (Loss) Reclassified from AOCI to Income	0		(4)		1
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	86	[5]	(25)	[5]	(163)	[5]
Virginia Electric and Power Company | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	0	[4]	(2)	[4]	(3)	[4]
Amount of Gain (Loss) Reclassified from AOCI to Income	0		(4)		0
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	5	[5]	10	[5]	(20)	[5]
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	0		(4)		(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
Virginia Electric and Power Company | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	9	[4],[6]	(6)	[4],[6]	(6)	[4],[6]
Amount of Gain (Loss) Reclassified from AOCI to Income	0	[6]	0	[6]	1	[6]
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	$ 81	[5],[6]	$ (35)	[5],[6]	$ (143)	[5],[6]

[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 deferred into AOCI have no associated effect in Virginia Power's Consolidated Statements of Income.

[5] 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.

[6] Amounts recorded in Virginia Power's Consolidated Statements of Income are classified in interest and related charges.

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Long-Term Debt (Total Long Term Debt) (Details) (USD $)	12 Months Ended						12 Months Ended							12 Months Ended		12 Months Ended																																				12 Months Ended											1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 1.4% to 7.195%, due 2013 to 2018	Dec. 31, 2013 2.75% to 8.875% due 2018 to 2042	Dec. 31, 2013 Unsecured Convertible Senior Notes, 2.125%, due 2023	Dec. 31, 2013 Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031	Dec. 31, 2013 7.5% and 8.375%, due 2064 and 2066	Dec. 31, 2013 Remarketable Subordinated Notes, 1.07% and 1.18%, due 2019 and 2021	Dec. 31, 2013 5.0% and 6.625%, due 2013 and 2014	Dec. 31, 2013 6.8% and 6.875%, due 2026 and 2027	Dec. 31, 2013 Secured Senior Notes, 5.13% to 5.78%, due 2013	Dec. 31, 2013 Secured Senior Note, 7.33%, due 2020	Dec. 31, 2013 2.25% to 5.75%, due 2033 to 2042	Dec. 31, 2013 5.25% Senior Notes Due 2033	Dec. 31, 2013 8.875% Senior Notes Due 2019	Dec. 31, 2013 Senior Notes Variable rates, due 2013 and 2014	Dec. 31, 2012 Senior Notes Variable rates, due 2013 and 2014	Dec. 31, 2013 Senior Notes 1.4% to 7.195%, due 2013 to 2018	Dec. 31, 2012 Senior Notes 1.4% to 7.195%, due 2013 to 2018	Dec. 31, 2013 Senior Notes 2.75% to 8.875% due 2018 to 2042	Dec. 31, 2012 Senior Notes 2.75% to 8.875% due 2018 to 2042	Dec. 31, 2013 Senior Notes Unsecured Convertible Senior Notes, 2.125%, due 2023	Dec. 31, 2012 Senior Notes Unsecured Convertible Senior Notes, 2.125%, due 2023	Dec. 31, 2013 Senior Notes Remarketable Subordinated Notes, 1.07% and 1.18%, due 2019 and 2021	Dec. 31, 2012 Senior Notes Remarketable Subordinated Notes, 1.07% and 1.18%, due 2019 and 2021	Dec. 31, 2013 Senior Notes 5.0% and 6.625%, due 2013 and 2014	Dec. 31, 2012 Senior Notes 5.0% and 6.625%, due 2013 and 2014	Dec. 31, 2013 Senior Notes 6.8% and 6.875%, due 2026 and 2027	Dec. 31, 2012 Senior Notes 6.8% and 6.875%, due 2026 and 2027	Dec. 31, 2013 Senior Notes Unsecured Senior Notes, 1.05% to 4.8%, due 2016 to 2043	Dec. 31, 2012 Senior Notes Unsecured Senior Notes, 1.05% to 4.8%, due 2016 to 2043	Dec. 31, 2013 Senior Notes Secured Senior Notes, 5.13% to 5.78%, due 2013	Dec. 31, 2012 Senior Notes Secured Senior Notes, 5.13% to 5.78%, due 2013	Dec. 31, 2013 Senior Notes Secured Senior Note, 7.33%, due 2020	Dec. 31, 2012 Senior Notes Secured Senior Note, 7.33%, due 2020	Dec. 31, 2013 Senior Notes Variable rate, due 2041	Dec. 31, 2012 Senior Notes Variable rate, due 2041	Dec. 31, 2013 Tax-Exempt Financings 2.25% to 5.75%, due 2033 to 2042	Dec. 31, 2012 Tax-Exempt Financings 2.25% to 5.75%, due 2033 to 2042	Dec. 31, 2013 Tax-Exempt Financings Variable rate, due 2041	Dec. 31, 2012 Tax-Exempt Financings Variable rate, due 2041	Dec. 31, 2013 Junior Subordinated Notes Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031	Dec. 31, 2012 Junior Subordinated Notes Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031	Dec. 31, 2013 Junior Subordinated Notes 7.5% and 8.375%, due 2064 and 2066	Dec. 31, 2012 Junior Subordinated Notes 7.5% and 8.375%, due 2064 and 2066	Dec. 31, 2013 Junior Subordinated Notes Enhanced Junior Subordinated Notes, variable rate, due 2066	Dec. 31, 2012 Junior Subordinated Notes Enhanced Junior Subordinated Notes, variable rate, due 2066	Dec. 31, 2013 Virginia Electric and Power Company	Dec. 31, 2012 Virginia Electric and Power Company	Dec. 31, 2013 Virginia Electric and Power Company Line of Credit	Dec. 31, 2013 Virginia Electric and Power Company 1.2% to 8.625%, due 2013 to 2018	Dec. 31, 2013 Virginia Electric and Power Company 2.75% to 8.875%, due 2019 to 2043	Dec. 31, 2013 Virginia Electric and Power Company 1.5% to 5.6%, due 2022 to 2040	Dec. 31, 2013 Virginia Electric and Power Company Senior Notes 1.2% to 8.625%, due 2013 to 2018	Dec. 31, 2012 Virginia Electric and Power Company Senior Notes 1.2% to 8.625%, due 2013 to 2018	Dec. 31, 2013 Virginia Electric and Power Company Senior Notes 2.75% to 8.875%, due 2019 to 2043	Dec. 31, 2012 Virginia Electric and Power Company Senior Notes 2.75% to 8.875%, due 2019 to 2043	Dec. 31, 2013 Virginia Electric and Power Company Tax-Exempt Financings Variable rates, due 2016 to 2041	Dec. 31, 2012 Virginia Electric and Power Company Tax-Exempt Financings Variable rates, due 2016 to 2041	Dec. 31, 2013 Virginia Electric and Power Company Tax-Exempt Financings 1.5% to 5.6%, due 2022 to 2040	Dec. 31, 2012 Virginia Electric and Power Company Tax-Exempt Financings 1.5% to 5.6%, due 2022 to 2040	May 31, 2013 Kincaid Power Station Secured Senior Note, 7.33%, due 2020	Jun. 30, 2013 Brayton Point Tax-Exempt Financings
Debt Instrument [Line Items]
Total principal, including VIE	$ 20,842,000,000	$ 18,988,000,000															$ 400,000,000	$ 400,000,000	$ 3,291,000,000	$ 3,541,000,000	$ 4,599,000,000	$ 4,599,000,000	$ 43,000,000	$ 82,000,000	$ 1,100,000,000	$ 0	$ 600,000,000	$ 622,000,000	$ 89,000,000	$ 89,000,000	$ 1,200,000,000	$ 0	$ 0	$ 842,000,000	$ 0	$ 145,000,000	$ 75,000,000	$ 0	$ 27,000,000	$ 284,000,000	$ 0	$ 75,000,000	$ 10,000,000	$ 268,000,000	$ 985,000,000	$ 985,000,000	$ 380,000,000	$ 380,000,000	$ 8,043,000,000	$ 6,676,000,000					$ 2,138,000,000	$ 2,306,000,000	$ 4,993,000,000	$ 3,408,000,000	$ 606,000,000	$ 454,000,000	$ 306,000,000	$ 508,000,000
Securities due within one year, including VIE	(1,519,000,000)	(2,223,000,000)																																															(58,000,000)	(418,000,000)
Unamortized discount and premium, net	(48,000,000)	(7,000,000)																																															(11,000,000)	(7,000,000)
Total long term debt, including VIE	19,330,000,000	16,851,000,000																																															7,974,000,000	6,251,000,000
Fair value hedge valuation	55,000,000	93,000,000
2013 Weighted- average Coupon	2.95%																0.37%		4.03%		5.64%				1.13%		5.00%		6.81%		3.13%						1.12%		2.38%				8.40%		8.11%		2.58%		4.10%						5.09%		5.25%		0.98%		3.16%
Debt instrument interest rate minimum				1.40%	2.75%		7.83%	7.50%	1.07%	5.00%	6.80%	5.03%		2.25%																																						1.20%	2.75%	1.50%
Debt instrument interest rate maximum				7.195%	8.875%		8.40%	8.375%	1.18%	6.625%	6.875%	5.78%		5.75%																																						8.625%	8.75%	5.60%
Credit facility, to support letters of credit																																																			120,000,000
Senior notes															510,000,000	600,000,000
RSN Annual Interest Rate						2.125%							7.33%		5.25%	8.875%
Long term debt maturity date															2033	2019
Redemption percentage of principal and accrued interest																100.00%
Percentage of the applicable conversion price	120.00%
Minimum consecutive trading days	20 days
Maximum consecutive trading days	30 days
Redemption percentage of principal amount	100.00%
Unamortized premium		18,000,000
Amount of notes redeemed	1,245,000,000	1,675,000,000	637,000,000																																																												185,000,000
Amount of bonds defeased																																																																257,000,000
Amount delivered to fund irrevocable trust																																																																284,000,000
Unamortized premium and discount	$ 14,000,000	$ 23,000,000

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Income Taxes (Earliest Tax Year) (Details)	12 Months Ended
	Dec. 31, 2013
Pennsylvania
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2010
Connecticut
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2010
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	2010	[1]
West Virginia
Operation In Major Geographical Areas Tax Year [Line Items]
Earliest Open Tax Year	2010

[1] Virginia is the only state considered major for Virginia Power's operations.

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Long-Term Debt

12 Months Ended

Dec. 31, 2013

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

LONG-TERM DEBT

At December 31,	2013 Weighted- average Coupon(1)		2013			2012
(millions, except percentages)
Virginia Electric and Power Company:
Unsecured Senior Notes:
1.2% to 8.625%, due 2013 to 2018	5.09	%	$	2,138		$	2,306
2.75% to 8.875%, due 2019 to 2043	5.25	%	4,993			3,408
Tax-Exempt Financings(2):
Variable rates, due 2016 to 2041	0.98	%	606			454
1.5% to 5.6%, due 2022 to 2040	3.16	%	306			508
Virginia Electric and Power Company total principal			$	8,043		$	6,676
Securities due within one year	4.10	%	(58		)	(418		)
Unamortized discount and premium, net			(11		)	(7		)
Virginia Electric and Power Company total long-term debt			$	7,974		$	6,251
Dominion Resources, Inc.:
Unsecured Senior Notes:
Variable rates, due 2013 and 2014	0.37	%	$	400		$	400
1.4% to 7.195%, due 2013 to 2018	4.03	%	3,291			3,541
2.75% to 8.875%, due 2019 to 2042(3)	5.64	%	4,599			4,599
Unsecured Convertible Senior Notes, 2.125%, due 2023(4)			43			82
Tax-Exempt Financing, variable rate, due 2041(5)	1.12	%	75			—
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031	8.40	%	10			268
Enhanced Junior Subordinated Notes:
7.5% and 8.375%, due 2064 and 2066	8.11	%	985			985
Variable rate, due 2066	2.58	%	380			380
Remarketable Subordinated Notes, 1.07% and 1.18%, due 2019 and 2021	1.13	%	1,100			—
Unsecured Debentures and Senior Notes(6):
5.0% and 6.625%, due 2013 and 2014	5.00	%	600			622
6.8% and 6.875%, due 2026 and 2027	6.81	%	89			89
Dominion Gas Holdings, LLC:
Unsecured Senior Notes, 1.05% to 4.8%, due 2016 to 2043	3.13	%	1,200			—
Dominion Energy, Inc.:
Secured Senior Notes:
5.03% to 5.78%, due 2013(7)			—			842
7.33%, due 2020(8)			—			145
Tax-Exempt Financings:
2.25% to 5.75%, due 2033 to 2042(9)	2.38	%	27			284
Variable rate, due 2041(5)			—			75
Virginia Electric and Power Company total principal (from above)			8,043			6,676
Dominion Resources, Inc. total principal			$	20,842		$	18,988
Fair value hedge valuation(10)			55			93
Securities due within one year(11)	2.95	%	(1,519		)	(2,223		)
Unamortized discount and premium, net			(48		)	(7		)
Dominion Resources, Inc. total long-term debt			$	19,330		$	16,851

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2013.

(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 2018.

(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, 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) Debt issued by the MDFA on behalf of Brayton Point. In connection with the sale of Brayton Point, the sole obligor under the bonds was changed from Brayton Point to Dominion in June 2013.

(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 of unamortized premium in 2012. The debt was non-recourse to Dominion and was secured by Juniper's assets. Dominion's purchase of Fairless in August 2013 resulted in the removal of the debt from Dominion's Consolidated Balance Sheet. See Note 15 for additional information.

(8) Represented debt associated with Kincaid. The debt was non-recourse to Dominion and was secured by the facility's assets and revenue. In connection with the sale of Kincaid, the notes were redeemed in May 2013 for approximately $185 million, including a make-whole premium and accrued interest.

(9) In 2012 included debt issued by the MDFA on behalf of Brayton Point. In connection with the sale of Brayton Point, three series of bonds totaling approximately $257 million were defeased in June 2013. In June 2013, Brayton Point delivered approximately $284 million to fund an irrevocable trust for the purpose of paying maturing principal and interest due through and including the earliest redemption dates of the bonds in 2016 and 2019.

(10) Represents the valuation of certain fair value hedges associated with Dominion's fixed rate debt.

(11) Includes $14 million fair value hedge valuation in 2013 and $23 million of net unamortized premium and fair value hedge valuation in 2012.

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, 2013, were as follows:

	2014			2015			2016			2017			2018			Thereafter			Total
(millions, except percentages)
Virginia Power	$	58		$	211		$	476		$	679		$	850		$	5,769		$	8,043
Weighted-average Coupon	4.10		%	5.39		%	5.25		%	5.44		%	4.17		%	4.78		%
Dominion
Unsecured Senior Notes	$	1,465		$	960		$	1,752		$	1,303		$	1,350		$	10,523		$	17,353
Tax-Exempt Financings	40			—			19			75			—			880			1,014
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts	—			—			—			—			—			10			10
Enhanced Junior Subordinated Notes	—			—			—			—			—			1,365			1,365
Remarketable Subordinated Notes	—			—			—			—			—			1,100			1,100
Total	$	1,505		$	960		$	1,771		$	1,378		$	1,350		$	13,878		$	20,842
Weighted-average Coupon	2.95		%	4.45		%	3.51		%	4.55		%	4.99		%	4.90		%

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, 2013, there were no events of default under these covenants.

In February 2014, Virginia Power issued $350 million of 3.45% senior notes, and $400 million of 4.45% senior notes, that mature in 2024, and 2044, respectively.

Convertible Securities

At December 31, 2013, Dominion had $43 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominion's common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. The conversion rate is subject to adjustment 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, 2013, the conversion rate had been adjusted to 29.8780 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $33.47, primarily due to individual dividend payments above the level paid at issuance. If the outstanding notes as of December 31, 2013 were all converted, it would result in the issuance of approximately 600 thousand additional shares of common stock. In January 2014, Dominion's Board of Directors declared dividends payable March 20, 2014 of 60 cents per share of common stock which will increase the conversion rate to 29.9961 effective as of February 26, 2014.

The senior notes are eligible for conversion during any calendar quarter when the closing price of Dominion's common stock was equal to or higher than 120% of the conversion price for at least 20 out of the last 30 consecutive trading days of the preceding quarter, the notes are called for redemption by Dominion and upon the occurrence of certain other conditions. During 2013, the senior notes were eligible for conversion and approximately $39 million of the notes were converted by holders into $28 million of common stock. The senior notes are eligible for conversion during the first quarter of 2014. 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 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 January 2013, Dominion repaid its $258 million7.83% unsecured junior subordinated debentures and redeemed all 250 thousand units of the $250 million7.83% Dominion Resources Capital Trust I capital securities due December 1, 2027. The securities were redeemed at a price of $1,019.58 per capital security plus accrued and unpaid distributions.

The following table provides summary information about the capital securities and junior subordinated notes outstanding as of December 31, 2013:

Date Established	Capital Trust	Units	Rate		Capital Securities Amount		Common Securities Amount
		(thousands)			(millions)
January 2001	Dominion Resources Capital Trust III(1)	10	8.4	%	$	10	$	0.3

(1) $10 million-Dominion Resources, Inc. 8.4% Debentures due 1/15/2031 were held as assets by the capital trust.

Interest charges related to Dominion's junior subordinated notes payable to affiliated trusts were $1 million for the year ended December 31, 2013 and $21 million for the years ended December 31, 2012 and 2011.

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 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 December 2011, 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.

Remarketable Subordinated Notes

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

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

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

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

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

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

Issuance Date	Units Issued	Total Net Proceeds		Total Long-term Debt		RSN Annual Interest Rate		Stock Purchase Contract Annual Rate		Stock Purchase Contract Liability(1)		Stock Purchase Settlement Date	RSN Maturity Date
(millions, except interest rates)
6/7/2013	11	$	533.5	$	550.0	1.070	%	5.055	%	$	76.7	4/1/2016	4/1/2021
6/7/2013	11	$	553.5	$	550.0	1.180	%	4.820	%	$	79.3	7/1/2016	7/1/2019

(1) Payments of $17 million were made in 2013. The stock purchase contract liability was $139 million at December 31, 2013.

Regulated Natural Gas Financing Plans

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

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
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	1,085	1,301	1,476
Granted, Shares	312	390	299
Vested, Shares	(356)	(596)	(617)
Cancelled and forfeited, Shares	(34)	(10)	(25)
Converted from goal-based stock to restricted stock, Shares			168
Nonvested ending, Shares	1,007	1,085	1,301
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	$ 44.46	$ 37.37	$ 38.20
Granted, Weighted Average Grant Date Fair Value	$ 54.70	$ 51.14	$ 43.68
Vested, Weighted Average Grant Date Fair Value	$ 39.00	$ 33.31	$ 40.72
Cancelled and forfeited, Weighted Average Grant Date Fair Value	$ 51.11	$ 42.99	$ 36.29
Converted from goal-based stock to restricted stock, Weighted - average Grant Date Fair Value			$ 30.99
Nonvested ending, Weighted Average Grant Date Fair Value	$ 49.35	$ 44.46	$ 37.37
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	4	12	161
Granted, Shares	4	1	3
Vested, Shares	(2)	(9)	(20)
Cancelled and forfeited, Shares	(1)		(132)
Converted from goal-based stock to restricted stock, Shares	1
Nonvested ending, Shares	5	4	12
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	$ 45.60	$ 39.19	$ 31.79
Granted, Weighted Average Grant Date Fair Value	$ 54.17	$ 52.48	$ 43.54
Vested, Weighted Average Grant Date Fair Value	$ 43.54	$ 37.46	$ 34.62
Cancelled and forfeited, Weighted Average Grant Date Fair Value	$ 43.54		$ 30.99
Nonvested ending, Weighted Average Grant Date Fair Value	$ 53.85	$ 45.60	$ 39.19

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Commitments and Contingencies (MF Global) (Details) (MF Global Bankruptcy, USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	Jan. 31, 2013	Dec. 31, 2013	Oct. 31, 2011
MF Global Bankruptcy
Loss Contingencies [Line Items]
Initial margin posted			$ 73
Margin received to date		17
Remaining margin claims sold to 3rd party	$ 56

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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, 2013		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss	$ (324)		$ (877)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss	1,709		2,865
Prior service (credit) cost	10		11
Total	1,719	[1]	2,876	[1]
Related expenses	1,700		2,900
Amount included in AOCI	1,000		1,800
Other Postretirement Plans
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss	(40)		229
Prior service (credit) cost	(271)		(71)
Total	(311)	[1]	158	[1]
Related expenses	(311)		158
Amount included in AOCI	$ (156)		$ 69

[1] As of December 31, 2013, of the $1.7 billion and $(311) million related to pension benefits and other postretirement benefits, $1.0 billion and $(156) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. 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.

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Fair Value Measurements (Net Change in the Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation [Roll Forward]
Included in earnings	$ (9)	$ (15)	$ (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	0	42	22
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	0	42	22
Commodity | Level 3 | Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation [Roll Forward]
Beginnning balance	25	(71)	(50)
Included in earnings	(9)	(15)	(77)
Included in other comprehensive income (loss)	1	101	14
Included in regulatory assets/liabilities	(9)	30	(42)
Settlements	(23)	47	88
Transfers out of Level 3	(1)	(67)	(4)
Ending balance	(16)	25	(71)
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	2	(28)	14
Included in earnings	(17)	(50)	(45)
Included in regulatory assets/liabilities	(9)	30	(42)
Settlements	17	50	45
Ending balance	$ (7)	$ 2	$ (28)

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Schedule of Depreciation Rates

Dominion's and Virginia Power's average composite depreciation rates on utility property, plant and equipment are as follows:

Year Ended December 31,	2013	2012	2011
(percent)
Dominion
Generation	2.71	2.62	2.68
Transmission	2.36	2.17	2.26
Distribution	3.13	3.17	3.19
Storage	2.43	2.59	2.64
Gas gathering and processing	2.39	2.49	2.52
General and other	3.82	4.55	4.66
Virginia Power
Generation	2.71	2.62	2.68
Transmission	2.28	1.98	2.03
Distribution	3.33	3.32	3.33
General and other	3.51	4.32	4.38

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	44 years
Merchant generation-other	15-36 years
General and other	5-59 years

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2013

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,	2013		2012
(millions)
Dominion
Utility:
Generation	$	14,018	$	13,707
Transmission	8,686		7,799
Distribution	11,714		11,071
Storage	2,190		2,137
Nuclear fuel	1,375		1,277
Gas gathering and processing	787		803
General and other	812		803
Other-including plant under construction	3,261		2,232
Total utility	42,843		39,829
Nonutility:
Merchant generation-nuclear	1,153		1,163
Merchant generation-other(1)	1,328		1,289
Nuclear fuel	770		775
Other-including plant under construction	875		1,265
Total nonutility	4,126		4,492
Total property, plant and equipment	$	46,969	$	44,321
Virginia Power
Utility:
Generation	$	14,018	$	13,707
Transmission	4,959		4,261
Distribution	9,103		8,701
Nuclear fuel	1,375		1,277
General and other	668		659
Other-including plant under construction	2,719		2,017
Total utility	32,842		30,622
Nonutility-other	6		9
Total property, plant and equipment	$	32,848	$	30,631

(1) 2012 amount includes $957 million due to consolidation of a VIE. See Note 15 for further information.

Jointly-Owned Power Stations

Dominion's and Virginia Power's proportionate share of jointly-owned power stations at December 31, 2013 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	$	1,038		$	2,486		$	568		$	1,007
Accumulated depreciation	(536		)	(1,109		)	(199		)	(262		)
Nuclear fuel	—			597			—			388
Accumulated amortization of nuclear fuel	—			(434		)	—			(283		)
Plant under construction	23			76			6			69

(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.

Assignment of Marcellus Acreage

In December 2013, DTI closed on agreements with two natural gas producers to convey approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. The agreements provide for payments to DTI, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013, Dominion received approximately $100 million in cash proceeds, resulting in an approximately $20 million ($12 million-after tax) gain and approximately $80 million deferred revenue, which will be recognized over the remaining terms of the agreements.

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Asset Retirement Obligations (Narrative) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations [Line Items]
Fair value, primarily of equity and debt securities	$ 3,900,000,000	$ 3,300,000,000
Nuclear decommissioning trust funds	3,903,000,000	3,330,000,000
Virginia Electric and Power Company
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds	$ 1,765,000,000	$ 1,515,000,000