Virginia Electric & Power 10-Q 2014 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended June 30, 2014

or

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

For the transition period from                     to                    

Commission File Number	Exact name of registrants as specified in their charters, address of principal executive offices and registrants’ telephone  number	I.R.S. Employer Identification Number
001-08489	DOMINION RESOURCES, INC.	54-1229715
001-02255	VIRGINIA ELECTRIC AND POWER COMPANY	54-0418825
333-195066	DOMINION GAS HOLDINGS, LLC	46-3639580

120 Tredegar Street

Richmond, Virginia 23219

(804) 819-2000

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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

Dominion Gas Holdings, LLC     Yes  ¨    No  x

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  ¨

Dominion Gas Holdings, LLC     Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Dominion Resources, Inc.

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

Virginia Electric and Power Company

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

Dominion Gas Holdings, LLC

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

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

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

Dominion Gas Holdings, LLC    Yes  ¨    No  x

At June 30, 2014, the latest practicable date for determination, Dominion Resources, Inc. had 582,667,882 shares of common stock outstanding and Virginia Electric and Power Company had 274,723 shares of common stock outstanding. Dominion Resources, Inc. is the sole holder of Virginia Electric and Power Company’s common stock. Dominion Resources, Inc. holds all of the membership interests of Dominion Gas Holdings, LLC.

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

DOMINION GAS HOLDINGS, LLC MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND IS FILING THIS FORM 10-Q UNDER THE REDUCED DISCLOSURE FORMAT.

COMBINED INDEX

		Page Number
	Glossary of Terms		3
	PART I. Financial Information
Item 1.	Financial Statements		6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		76
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		92
Item 4.	Controls and Procedures		94
	PART II. Other Information
Item 1.	Legal Proceedings		95
Item 1A.	Risk Factors		95
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		97
Item 6.	Exhibits		97

PAGE 2

GLOSSARY OF TERMS

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

Abbreviation or Acronym	Definition
2013 Equity Units	Dominion's 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013
2014 Equity Units	Dominion's 2014 Series A Equity Units issued in July 2014
AFUDC	Allowance for funds used during construction
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
BACT	Best available control technology
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
BOD	Board of Directors
BP	BP Wind Energy North America Inc.
Brayton Point	Brayton Point power station
BREDL	Blue Ridge Environmental Defense League
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
CEO	Chief Executive Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
CFO	Chief Financial Officer
CO2	Carbon dioxide
COL	Combined Construction Permit and Operating License
Companies	Dominion, Virginia Power and Dominion Gas, collectively
Cooling degree days	Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
Corporate Unit	A stock purchase contract and 1/20 interest in a RSN issued by Dominion
Cove Point	Dominion Cove Point LNG, LP
Cove Point LNG Facility	An LNG import/regasification and storage facility located on the Chesapeake Bay in Lusby, Maryland
CPCN	Certificate of Public Convenience and Necessity
CSAPR	Cross State Air Pollution Rule
CWA	Clean Water Act
D.C.	District of Columbia
DEI	Dominion Energy, Inc.
DOE	Department of Energy
Dominion	The legal entity, Dominion Resources, Inc., one or more of its consolidated subsidiaries (other than Virginia Power and Dominion Gas) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries
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 Gas 2013 Senior Notes	The $400 million 2013 Series A 1.05% Senior Notes due 2016, $400 million 2013 Series B 3.55% Senior Notes due 2023 and $400 million 2013 Series C 4.80% Senior Notes due 2043
Dominion Iroquois	Dominion Iroquois, Inc., which holds a 24.72% general partnership interest in Iroquois
Dominion NGL Pipelines, LLC	The initial owner of the 58-mile G-150 pipeline project, which is designed to transport approximately 27,000 barrels per day of NGLs from Natrium to an interconnect with the ATEX line of Enterprise near Follansbee, West Virginia

PAGE 3

Abbreviation or Acronym	Definition
DRS	Dominion Resources Services, Inc.
DSM	Demand-side management
Dth	Dekatherm
DTI	Dominion Transmission, Inc.
DVP	Dominion Virginia Power operating segment
East Ohio	The East Ohio Gas Company, doing business as Dominion East Ohio
Elwood	Elwood power station
Energy Capital Partners	A private equity firm with offices in Short Hills, New Jersey and San Diego, California
Enterprise	Enterprise Product Partners, L.P.
EPA	Environmental Protection Agency
EPC	Engineering, procurement and construction
EPS	Earnings per share
ESBWR	General Electric-Hitachi's Economic Simplified Boiling Water Reactor
FERC	Federal Energy Regulatory Commission
Flex MMP Stock	Virginia Power's Flexible Money Market Cumulative Preferred Stock 2002 Series A
Fowler Ridge	A wind-turbine facility joint venture between Dominion and BP in Benton County, Indiana
FTRs	Financial transmission rights
GAAP	U.S. generally accepted accounting principles
Gal	Gallon
GHG	Greenhouse gas
Heating degree days	Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
House Bill 95	Ohio utility reform legislation effective September 2011
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
IRCA	Intercompany revolving credit agreement
Iroquois	Iroquois Gas Transmission System L.P.
ISO	Independent system operator
ISO-NE	ISO New England
June 2009 hybrids	2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to extensions to no later than 2079
Kewaunee	Kewaunee nuclear power station
Kincaid	Kincaid power station
kV	Kilovolt
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
Maryland Commission	Public Service Commission of Maryland
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MGD	Million gallons a day
Millstone	Millstone nuclear power station
MISO	Midcontinent Independent Transmission System Operator, Inc.
MLP	Master limited partnership
Moody’s	Moody’s Investors Service
MW	Megawatt
MWh	Megawatt hour
Natrium	A natural gas and fractionation facility located in Natrium, West Virginia, owned by Blue Racer
NCEMC	North Carolina Electric Membership Corporation
NedPower	A wind-turbine facility joint venture between Dominion and Shell in Grant County, West Virginia
NGLs	Natural gas liquids
North Anna	North Anna nuclear power station

PAGE 4

Abbreviation or Acronym	Definition
North Carolina Commission	North Carolina Utilities Commission
Northern System	Collection of approximately 131 miles of various diameter natural gas pipelines in Ohio
NOx	Nitrogen oxide
NPDES	National Pollutant Discharge Elimination System
NRC	Nuclear Regulatory Commission
NSPS	New Source Performance Standards
NYSE	New York Stock Exchange
ODEC	Old Dominion Electric Cooperative
Ohio Commission	Public Utilities Commission of Ohio
Order 1000	Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development
PIPP	Percentage of Income Payment Plan
PIR	Pipeline Infrastructure Replacement program deployed by East Ohio
PJM	PJM Interconnection, L.L.C.
ppb	Parts-per-billion
PSD	Prevention of Significant Deterioration
RCC	Replacement Capital Covenant
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
RSN	Remarketable subordinated note
RTO	Regional transmission organization
SEC	Securities and Exchange Commission
Shell	Shell WindEnergy, Inc.
SO2	Sulfur dioxide
Standard & Poor’s	Standard & Poor’s Ratings Services, a division of McGraw Hill Financial, Inc.
Surry	Surry nuclear power station
U.S.	United States of America
UAO	Unilateral Administrative Order
UEX Rider	Uncollectible Expense Rider deployed by East Ohio
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
Warren County	A 1,329 MW combined-cycle, natural gas-fired power station under construction in Warren County, Virginia

PAGE 5

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014		2013
(millions, except per share amounts)
Operating Revenue	$	2,813	$	2,980		$	6,443	$	6,503
Operating Expenses
Electric fuel and other energy-related purchases		633		875			1,967		1,826
Purchased electric capacity		87		88			175		176
Purchased gas		324		297			864		764
Other operations and maintenance		933		728			1,358		1,351
Depreciation, depletion and amortization		308		303			616		600
Other taxes		134		141			301		308
Total operating expenses		2,419		2,432			5,281		5,025
Income from operations		394		548			1,162		1,478
Other income		57		49			97		136
Interest and related charges		227		203			464		431
Income from continuing operations including noncontrolling interests before income tax expense		224		394			795		1,183
Income tax expense		63		116			249		404
Income from continuing operations including noncontrolling interests		161		278			546		779
Loss from discontinued operations(1)		—		(70	)		—		(69	)
Net Income Including Noncontrolling Interests		161		208			546		710
Noncontrolling Interests		2		6			8		13
Net Income Attributable to Dominion	$	159	$	202		$	538	$	697
Amounts Attributable to Dominion:
Income from continuing operations, net of tax	$	159	$	272		$	538	$	766
Loss from discontinued operations, net of tax		—		(70	)		—		(69	)
Net income attributable to Dominion	$	159	$	202		$	538	$	697
Earnings Per Common Share-Basic
Income from continuing operations	$	0.27	$	0.47		$	0.92	$	1.33
Loss from discontinued operations		—		(0.12	)		—		(0.12	)
Net income attributable to Dominion	$	0.27	$	0.35		$	0.92	$	1.21
Earnings Per Common Share-Diluted
Income from continuing operations	$	0.27	$	0.47		$	0.92	$	1.33
Loss from discontinued operations		—		(0.12	)		—		(0.12	)
Net income attributable to Dominion	$	0.27	$	0.35		$	0.92	$	1.21
Dividends declared per common share	$	0.6000	$	0.5625		$	1.2000	$	1.1250

(1) Includes income tax benefit of $49 million for both the three and six months ended June 30, 2013.

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

PAGE 6

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
(millions)
Net income including noncontrolling interests	$	161		$	208		$	546		$	710
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		(59	)		122			(209	)		32
Changes in unrealized net gains on investment securities(2)		49			3			78			81
Changes in unrecognized pension and other postretirement benefit costs(3)		4			228			—			228
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities(4)		(16	)		(17	)		144			59
Net realized gains on investment securities(5)		(7	)		(9	)		(18	)		(36	)
Net pension and other postretirement benefit costs(6)		9			10			17			30
Changes in other comprehensive income (loss) from equity method investees(7)		2			—			(5	)		—
Total other comprehensive income (loss)		(18	)		337			7			394
Comprehensive income including noncontrolling interests		143			545			553			1,104
Comprehensive income attributable to noncontrolling interests		2			6			8			13
Comprehensive income attributable to Dominion	$	141		$	539		$	545		$	1,091

(1) Net of $47 million and $(76) million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $126 million and $(22) million for the six months ended June 30, 2014 and 2013, respectively.

(2) Net of $(27) million and $— million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $(28) million and $(51) million for the six months ended June 30, 2014 and 2013, respectively.

(3) Net of $4 million and $(148) million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $— million and $(148) million for the six months ended June 30, 2014 and 2013, respectively.

(4) Net of $6 million and $9 million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $(94) million and $(39) million for the six months ended June 30, 2014 and 2013, respectively.

(5) Net of $4 million and $5 million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $11 million and $23 million for the six months ended June 30, 2014 and 2013, respectively.

(6) Net of $(6) million and $(11) million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $(12) million and $(20) million for the six months ended June 30, 2014 and 2013, respectively.

(7) Net of $3 million and $— million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $3 million and $— million for the six months ended June 30, 2014 and 2013, respectively.

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

PAGE 7

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2014			December 31, 2013(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	419		$	316
Customer receivables (less allowance for doubtful accounts of $23 and $25)		1,476			1,695
Other receivables (less allowance for doubtful accounts of $3 and $4)		161			141
Inventories		1,261			1,176
Prepayments		224			192
Other		2,020			2,420
Total current assets		5,561			5,940
Investments
Nuclear decommissioning trust funds		4,103			3,903
Investment in equity method affiliates		1,083			916
Other		272			283
Total investments		5,458			5,102
Property, Plant and Equipment
Property, plant and equipment		48,698			46,969
Accumulated depreciation, depletion and amortization		(14,811	)		(14,341	)
Total property, plant and equipment, net		33,887			32,628
Deferred Charges and Other Assets
Goodwill		3,044			3,086
Regulatory assets		1,375			1,228
Other		2,174			2,112
Total deferred charges and other assets		6,593			6,426
Total assets	$	51,499		$	50,096

(1) Dominion’s Consolidated Balance Sheet at December 31, 2013 has been derived from the audited Consolidated Financial Statements at that date.

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

PAGE 8

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	June 30, 2014			December 31, 2013(1)
(millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Securities due within one year	$	865		$	1,519
Short-term debt		3,080			1,927
Accounts payable		852			1,168
Derivative liabilities		964			828
Other		1,482			1,552
Total current liabilities		7,243			6,994
Long-Term Debt
Long-term debt		18,018			16,877
Junior subordinated notes		1,373			1,373
Remarketable subordinated notes		1,082			1,080
Total long-term debt		20,473			19,330
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		7,237			7,114
Asset retirement obligations		1,515			1,484
Regulatory liabilities		2,011			2,001
Other		1,319			1,274
Total deferred credits and other liabilities		12,082			11,873
Total liabilities		39,798			38,197
Commitments and Contingencies (see Note 15)
Subsidiary Preferred Stock Not Subject to Mandatory Redemption		134			257
Common Shareholders’ Equity
Common stock – no par(2)		5,861			5,783
Retained earnings		6,023			6,183
Accumulated other comprehensive loss		(317	)		(324	)
Total common shareholders’ equity		11,567			11,642
Total liabilities and shareholders’ equity	$	51,499		$	50,096

(1) Dominion’s Consolidated Balance Sheet at December 31, 2013 has been derived from the audited Consolidated Financial Statements at that date.

(2) 1 billion shares authorized; 583 million shares and 581 million shares outstanding at June 30, 2014 and December 31, 2013, respectively.

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

PAGE 9

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,	2014			2013
(millions)
Operating Activities
Net income including noncontrolling interests	$	546		$	710
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)		748			729
Deferred income taxes and investment tax credits		301			395
Gains on the sale of assets		(159	)		(25	)
Charges associated with North Anna and offshore wind legislation		287			—
Other adjustments		(55	)		(12	)
Changes in:
Accounts receivable		153			92
Inventories		2			(10	)
Deferred fuel and purchased gas costs, net		(322	)		48
Prepayments		(34	)		(88	)
Accounts payable		(258	)		(149	)
Accrued interest, payroll and taxes		(50	)		(67	)
Margin deposit assets and liabilities		204			21
Other operating assets and liabilities		84			147
Net cash provided by operating activities		1,447			1,791
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(2,389	)		(1,937	)
Acquisition of solar development projects		(58	)		(13	)
Proceeds from sales of securities		686			862
Purchases of securities		(703	)		(885	)
Proceeds from the sale of assets to Blue Racer		84			47
Proceeds from the sale of electric retail energy marketing business		187			—
Restricted cash equivalents		8			23
Other		(1	)		18
Net cash used in investing activities		(2,186	)		(1,885	)
Financing Activities
Issuance (repayment) of short-term debt, net		1,152			(307	)
Issuance of long-term debt		1,150			2,350
Repayment of long-term debt, including redemption premiums		(660	)		(1,185	)
Repayment of junior subordinated notes		—			(258	)
Subsidiary preferred stock redemption		(125	)		—
Issuance of common stock		71			144
Common dividend payments		(698	)		(650	)
Subsidiary preferred dividend payments		(6	)		(8	)
Other		(42	)		(50	)
Net cash provided by financing activities		842			36
Increase (decrease) in cash and cash equivalents		103			(58	)
Cash and cash equivalents at beginning of period		316			248
Cash and cash equivalents at end of period	$	419		$	190
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	309		$	172

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

PAGE 10

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
(millions)
Operating Revenue(1)	$	1,729	$	1,710	$	3,712	$	3,491
Operating Expenses
Electric fuel and other energy-related purchases(1)		518		528		1,168		1,098
Purchased electric capacity		87		88		175		176
Other operations and maintenance:
Affiliated suppliers		70		81		141		155
Other		563		274		833		519
Depreciation and amortization		217		211		435		418
Other taxes		69		65		142		132
Total operating expenses		1,524		1,247		2,894		2,498
Income from operations		205		463		818		993
Other income		21		27		36		52
Interest and related charges		103		84		210		177
Income before income tax expense		123		406		644		868
Income tax expense		54		141		251		316
Net Income		69		265		393		552
Preferred dividends		2		4		8		8
Balance available for common stock	$	67	$	261	$	385	$	544

(1) See Note 17 for amounts attributable to affiliates.

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

PAGE 11

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014			2013
(millions)
Net income	$	69		$	265	$	393		$	552
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		(1	)		1		1			3
Changes in unrealized net gains on nuclear decommissioning trust funds(2)		6			—		8			8
Amounts reclassified to net income:
Net derivative gains-hedging activities(3)		(1	)		—		(4	)		—
Net realized gains on nuclear decommissioning trust funds(4)		—			—		(2	)		(1	)
Other comprehensive income		4			1		3			10
Comprehensive income	$	73		$	266	$	396		$	562

(1) Net of $— million and $(1) million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $— million and $(2) million for the six months ended June 30, 2014 and 2013, respectively.

(2) Net of $(3) million and $— million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $(5) million for both the six months ended June 30, 2014 and 2013.

(3) Net of $— million tax for both the three months ended June 30, 2014 and 2013, and net of $2 million and $— million for the six months ended June 30, 2014 and 2013, respectively.

(4) Net of $— million tax for both the three months ended June 30, 2014 and 2013, and net of $1 million for both the six months ended June 30, 2014 and 2013.

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

PAGE 12

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2014			December 31, 2013(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	58		$	16
Customer receivables (less allowance for doubtful accounts of $12 and $11)		926			946
Other receivables (less allowance for doubtful accounts of $2 at both dates)		73			78
Inventories (average cost method)		839			808
Prepayments		170			32
Other		279			283
Total current assets		2,345			2,163
Investments
Nuclear decommissioning trust funds		1,857			1,765
Other		4			12
Total investments		1,861			1,777
Property, Plant and Equipment
Property, plant and equipment		33,938			32,848
Accumulated depreciation and amortization		(10,896	)		(10,580	)
Total property, plant and equipment, net		23,042			22,268
Deferred Charges and Other Assets
Intangible assets, net		202			193
Regulatory assets		561			417
Other(2)		197			143
Total deferred charges and other assets		960			753
Total assets	$	28,208		$	26,961

(1) Virginia Power’s Consolidated Balance Sheet at December 31, 2013 has been derived from the audited Consolidated Financial Statements at that date.

(2) See Note 17 for amounts attributable to affiliates.

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

PAGE 13

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	June 30, 2014		December 31, 2013(1)
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	14	$	58
Short-term debt		1,323		842
Accounts payable		456		479
Payables to affiliates		81		69
Affiliated current borrowings		—		97
Accrued interest, payroll and taxes		224		218
Other(2)		452		454
Total current liabilities		2,550		2,217
Long-Term Debt		8,716		7,974
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		4,266		4,137
Asset retirement obligations		704		689
Regulatory liabilities		1,607		1,597
Other(2)		314		292
Total deferred credits and other liabilities		6,891		6,715
Total liabilities		18,157		16,906
Commitments and Contingencies (see Note 15)
Preferred Stock Not Subject to Mandatory Redemption		134		257
Common Shareholder’s Equity
Common stock – no par(3)		5,738		5,738
Other paid-in capital		1,113		1,113
Retained earnings		3,015		2,899
Accumulated other comprehensive income		51		48
Total common shareholder’s equity		9,917		9,798
Total liabilities and shareholder’s equity	$	28,208	$	26,961

(1) Virginia Power’s Consolidated Balance Sheet at December 31, 2013 has been derived from the audited Consolidated Financial Statements at that date.

(2) See Note 17 for amounts attributable to affiliates.

(3) 500,000 shares authorized; 274,723 shares outstanding at June 30, 2014 and December 31, 2013.

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

PAGE 14

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,	2014			2013
(millions)
Operating Activities
Net income	$	393		$	552
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		521			499
Deferred income taxes and investment tax credits		246			199
Charges associated with North Anna and offshore wind legislation		287			—
Other adjustments		(17	)		(39	)
Changes in:
Accounts receivable		26			(52	)
Inventories		(31	)		(4	)
Deferred fuel expenses		(359	)		(4	)
Prepayments		(138	)		(47	)
Accounts payable		18			(30	)
Other operating assets and liabilities		(37	)		41
Net cash provided by operating activities		909			1,115
Investing Activities
Plant construction and other property additions		(1,385	)		(1,217	)
Purchases of nuclear fuel		(131	)		(90	)
Proceeds from sales of securities		299			324
Purchases of securities		(311	)		(354	)
Other		(11	)		—
Net cash used in investing activities		(1,539	)		(1,337	)
Financing Activities
Issuance of short-term debt, net		481			92
Repayment of affiliated current borrowings, net		(97	)		(385	)
Issuance of long-term debt		750			1,250
Repayment of long-term debt		(50	)		(459	)
Preferred stock redemption		(125	)		—
Common dividend payments		(270	)		(268	)
Preferred dividend payments		(6	)		(8	)
Other		(11	)		(14	)
Net cash provided by financing activities		672			208
Increase (decrease) in cash and cash equivalents		42			(14	)
Cash and cash equivalents at beginning of period		16			28
Cash and cash equivalents at end of period	$	58		$	14
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	236		$	100

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

PAGE 15

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
(millions)
Operating Revenue(1)	$	428	$	430	$	997	$	1,016
Operating Expenses
Purchased gas(1)		76		63		213		177
Other energy-related purchases		5		18		21		40
Other operations and maintenance:
Affiliated suppliers		16		17		37		39
Other(2)		93		161		125		269
Depreciation and amortization		49		50		96		99
Other taxes		35		33		86		80
Total operating expenses		274		342		578		704
Income from operations		154		88		419		312
Other income		5		3		13		14
Interest and related charges(1)		6		6		12		13
Income from operations before income taxes		153		85		420		313
Income tax expense		60		32		163		122
Net Income	$	93	$	53	$	257	$	191

(1) See Note 17 for amounts attributable to related parties.

(2) Includes gains on the sales of assets to an affiliate of $59 million and $25 million for the six months ended June 30, 2014 and 2013, respectively. See Note 10 for more information.

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

PAGE 16

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014			2013
(millions)
Net income	$	93		$	53	$	257		$	191
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		(19	)		52		(27	)		66
Changes in net unrecognized pension and other postretirement benefit costs(2)		—			13		(1	)		13
Amounts reclassified to net income:
Net derivative losses-hedging activities(3)		3			—		8			3
Net pension and other postretirement benefit costs(4)		1			1		3			3
Other comprehensive income (loss)		(15	)		66		(17	)		85
Comprehensive income	$	78		$	119	$	240		$	276

(1) Net of $12 million and $(33) million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $17 million and $(43) million for the six months ended June 30, 2014 and 2013, respectively.

(2) Net of $— million and $(9) million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $(1) million and $(9) million for the six months ended June 30, 2014 and 2013, respectively.

(3) Net of $(2) million and $— million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $(4) million and $(1) million for the six months ended June 30, 2014 and 2013, respectively.

(4) Net of $— million and $(1) million tax for the three months ended June 30, 2014 and 2013, respectively, and net of $(1) million and $(2) million for the six months ended June 30, 2014 and 2013, respectively.

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

PAGE 17

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2014			December 31, 2013(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	10		$	8
Customer receivables (less allowance for doubtful accounts of $4 and $5)(2)		293			311
Affiliated receivables		6			41
Inventories		81			63
Prepayments		46			67
Other(2)		235			311
Total current assets		671			801
Investments		114			106
Property, Plant and Equipment
Property, plant and equipment		8,426			8,240
Accumulated depreciation and amortization		(2,476	)		(2,421	)
Total property, plant and equipment, net		5,950			5,819
Deferred Charges and Other Assets
Goodwill		542			545
Intangible assets, net		80			82
Regulatory assets		304			285
Pension and other postretirement benefit assets(2)		1,493			1,436
Other(2)		66			68
Total deferred charges and other assets		2,485			2,416
Total assets	$	9,220		$	9,142

(1) Dominion Gas’ Consolidated Balance Sheet at December 31, 2013 has been derived from the Audited Consolidated Financial Statements at that date.

(2) See Note 17 for amounts attributable to related parties.

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

PAGE 18

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	June 30, 2014			December 31, 2013(1)
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	126		$	277
Payables to affiliates		13			45
Affiliated current borrowings		1,471			1,342
Accrued interest, payroll and taxes		187			209
Other(2)		211			197
Total current liabilities		2,008			2,070
Long-Term Debt		1,199			1,198
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,003			1,977
Other(2)		483			470
Total deferred credits and other liabilities		2,486	��		2,447
Total liabilities		5,693			5,715
Commitments and Contingencies (see Note 15)
Equity
Membership interests		3,602			3,485
Accumulated other comprehensive loss		(75	)		(58	)
Total equity		3,527			3,427
Total liabilities and equity	$	9,220		$	9,142

(1) Dominion Gas’ Consolidated Balance Sheet at December 31, 2013 has been derived from the Audited Consolidated Financial Statements at that date.

(2) See Note 17 for amounts attributable to related parties.

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

PAGE 19

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,	2014			2013
(millions)
Operating Activities
Net income	$	257		$	191
Adjustments to reconcile net income to net cash provided by operating activities:
Gains on sales of assets to an affiliate		(59	)		(25	)
Depreciation and amortization		96			99
Deferred income taxes and investment tax credits		48			47
Other adjustments		(7	)		(8	)
Changes in:
Accounts receivable		12			75
Deferred purchased gas costs, net		40			47
Prepayments		21			28
Inventories		(18	)		(7	)
Accounts payable		(152	)		(96	)
Payables to affiliates		(32	)		(10	)
Accrued interest, payroll and taxes		(22	)		(21	)
Other operating assets and liabilities		(23	)		(22	)
Net cash provided by operating activities		161			298
Investing Activities
Plant construction and other property additions		(249	)		(253	)
Proceeds from sale of assets to an affiliate		47			108
Other		(6	)		1
Net cash used in investing activities		(208	)		(144	)
Financing Activities
Issuance (repayment) of affiliated current borrowings, net		196			(150	)
Distribution payments		(145	)		—
Other		(2	)		—
Net cash provided by (used in) financing activities		49			(150	)
Increase in cash and cash equivalents		2			4
Cash and cash equivalents at beginning of period		8			12
Cash and cash equivalents at end of period	$	10		$	16
Supplemental Cash Flow Information
Significant noncash investing and financing activities:
Accrued capital expenditures	$	40		$	38
Extinguishment of affiliated current borrowings in exchange for assets sold to affiliate		67			—

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

PAGE 20

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Gas. Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Dominion Gas is a holding company that conducts business activities through a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution operations in Ohio, and gas gathering and processing activities primarily in West Virginia, Ohio and Pennsylvania. Dominion Gas' wholly-owned subsidiaries are DTI, East Ohio and Dominion Iroquois.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the SEC, the Companies’ accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with GAAP. These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013, Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 and Exhibits 99.11(b) and 99.11(c) to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014.

In the Companies’ opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position as of June 30, 2014, their results of operations for the three and six months ended June 30, 2014 and 2013, and their cash flows for the six months ended June 30, 2014 and 2013. Such adjustments are normal and recurring in nature unless otherwise noted.

The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

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

The results of operations for interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, rate changes, electric fuel and other energy-related purchases, purchased gas expenses and other factors.

Certain amounts in the Companies' 2013 Consolidated Financial Statements and Notes have been reclassified to conform to the 2014 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 and/or Dominion Gas, where applicable.

Note 3. Acquisitions and Dispositions

Dominion

Acquisition of Solar Development Projects

In March 2014, Dominion completed the acquisition of 100% of the equity interests of six solar development projects in California from Recurrent Energy Development Holdings, LLC for approximately $50 million. The projects are expected to cost approximately $450 million once constructed, including the initial acquisition cost. Upon completion, the facilities are expected to generate approximately 139 MW and will provide Dominion with a large utility-scale solar presence in the California market and significantly increase its solar generation portfolio.

In May 2014, Dominion completed the acquisition of 100% of the equity interests of two solar development projects in Tennessee from Strata Solar Development, LLC for $2 million. The projects are expected to cost approximately $70 million once constructed, including the initial acquisition cost. Upon completion, the facilities are expected to generate approximately 32 MW.

PAGE 21

The purchase price for each of these acquisitions was allocated to Property, Plant and Equipment.

In May 2014, Dominion entered into an agreement to acquire 100% of the equity interests of a solar project in California from EDF Renewable Development, Inc. for approximately $70 million. The acquisition is expected to close later this year prior to the project commencing operations. The project is expected to cost approximately $75 million once constructed, including the initial acquisition cost. Upon completion, the facilities are expected to generate approximately 20 MW.

Long-term power purchase, interconnection, EPC and operation and maintenance agreements have been executed for each of the acquired projects. Construction of the projects has commenced and all of the solar facilities are expected to enter commercial operations in late 2014. Dominion expects to claim federal investment tax credits on the projects.

Sale of Electric Retail Energy Marketing Business

In March 2014, Dominion completed the sale of its electric retail energy marketing business. The proceeds were approximately $187 million, net of transaction costs. The sale resulted in a gain, subject to post-closing adjustments, of approximately $100 million ($57 million after-tax) net of a $31 million write-off of goodwill, and is included in other operations and maintenance expense in Dominion's Consolidated Statements of Income. The sale of the electric retail energy marketing business did not qualify for discontinued operations classification.

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 Statements of Income. The sale of Illinois Gas Contracts did not qualify for discontinued operations classification.

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 August 2013, Dominion completed the sale and received proceeds of approximately $465 million, net of transaction costs.

In the first and second quarters of 2013, Brayton Point’s and Kincaid’s assets and liabilities to be disposed of were classified as held for sale and adjusted to their estimated fair value less cost to sell, resulting in impairment charges totaling $48 million ($28 million after-tax) for the six month period ended June 30, 2013, including $11 million ($6 million after-tax) for the three month period ended June 30, 2013, which are included in discontinued operations in Dominion’s Consolidated Statements of Income. 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.

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

	Three Months Ended June 30,			Six Months Ended June 30,
	2013			2013
(millions)
Operating revenue	$	63		$	217
Income before income taxes(1)		(119	)		(118	)

(1) Includes $64 million of charges related to the defeasance of Brayton Point debt and the early redemption of Kincaid debt. See Note 17 in Dominion's Annual Report on Form 10-K for the year ended December 31, 2013 for more information.

Dominion Gas

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

PAGE 22

interest in gas produced from the acreage. During the six months ended June 30, 2014, DTI received $16 million in additional cash proceeds resulting from post-closing adjustments. At June 30, 2014, deferred revenue totaled approximately $91 million, which is expected to be recognized over a period of approximately nine years.

Dominion and Dominion Gas

Blue Racer

See Note 10 for a discussion of transactions related to Blue Racer.

Note 4. Operating Revenue

The Companies’ operating revenue consists of the following:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
(millions)
Dominion
Electric sales:
Regulated	$	1,697	$	1,687	$	3,648	$	3,448
Nonregulated		320		545		1,174		1,203
Gas sales:
Regulated		70		49		217		181
Nonregulated		228		208		345		553
Gas transportation and storage		351		360		795		827
Other		147		131		264		291
Total operating revenue	$	2,813	$	2,980	$	6,443	$	6,503
Virginia Power
Regulated electric sales	$	1,697	$	1,687	$	3,648	$	3,448
Other		32		23		64		43
Total operating revenue	$	1,729	$	1,710	$	3,712	$	3,491
Dominion Gas
Gas sales:
Regulated	$	54	$	34	$	137	$	108
Nonregulated		4		4		13		7
Gas transportation and storage		304		312		700		731
NGL revenue		44		66		101		138
Other		22		14		46		32
Total operating revenue	$	428	$	430	$	997	$	1,016

Note 5. Income Taxes

For continuing operations, including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies' effective income tax rate as follows:

	Dominion						Virginia Power						Dominion Gas
Six Months Ended June 30,	2014			2013			2014			2013			2014			2013
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		1.5			1.9			3.8			2.6			3.7			3.8
Investment and production tax credits		(5.9	)		(1.5	)		(0.6	)		—			—			—
Valuation allowances		1.1			—			—			—			—			—
Other, net		(0.4	)		(1.3	)		0.6			(1.2	)		0.1			0.2
Effective tax rate		31.3	%		34.1	%		38.8	%		36.4	%		38.8	%		39.0	%

PAGE 23

In 2014, there have been no material changes in the Companies’ unrecognized tax benefits or expectations regarding possible changes that could reasonably occur during the next twelve months. See Note 5 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 and Note 5 in Exhibit 99.11(b) to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014 for a discussion of these unrecognized tax benefits.

Note 6. Earnings Per Share

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
(millions, except EPS)
Net income attributable to Dominion	$	159	$	202	$	538	$	697
Average shares of common stock outstanding – Basic		581.9		578.1		581.7		577.3
Net effect of dilutive securities(1)		2.0		0.8		1.7		0.9
Average shares of common stock outstanding – Diluted		583.9		578.9		583.4		578.2
Earnings Per Common Share – Basic	$	0.27	$	0.35	$	0.92	$	1.21
Earnings Per Common Share – Diluted	$	0.27	$	0.35	$	0.92	$	1.21

(1) Dilutive securities consist primarily of contingently convertible senior notes and the 2013 Equity Units for 2014 and contingently convertible senior notes for 2013. See Note 14 in this report and Note 17 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 for more information.

There were no potentially dilutive securities excluded from the calculation of diluted EPS for the three and six months ended June 30, 2014. The 2013 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and six months ended June 30, 2013. See Note 17 to the Consolidated Financial Statements in Dominion's and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 for more information.

PAGE 24

Note 7. Accumulated Other Comprehensive Income

Dominion

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			Other comprehensive income (loss) from equity method investee			Total
(millions)
Three Months Ended June 30, 2014
Beginning balance	$	(278	)	$	492		$	(506	)	$	(7	)	$	(299	)
Other comprehensive income before reclassifications: gains (losses)		(59	)		49			4			2			(4	)
Amounts reclassified from accumulated other comprehensive income(1): (gains) losses		(16	)		(7	)		9			—			(14	)
Net current-period other comprehensive income (loss)		(75	)		42			13			2			(18	)
Ending balance	$	(353	)	$	534		$	(493	)	$	(5	)	$	(317	)
Three Months Ended June 30, 2013
Beginning balance	$	(136	)	$	377		$	(1,061	)	$	—		$	(820	)
Other comprehensive income before reclassifications: gains (losses)		122			3			228			—			353
Amounts reclassified from accumulated other comprehensive income(1): (gains) losses		(17	)		(9	)		10			—			(16	)
Net current-period other comprehensive income (loss)		105			(6	)		238			—			337
Ending balance	$	(31	)	$	371		$	(823	)	$	—		$	(483	)
Six Months Ended June 30, 2014
Beginning balance	$	(288	)	$	474		$	(510	)	$	—		$	(324	)
Other comprehensive income before reclassifications: gains (losses)		(209	)		78			—			(5	)		(136	)
Amounts reclassified from accumulated other comprehensive income(1): (gains) losses		144			(18	)		17			—			143
Net current-period other comprehensive income (loss)		(65	)		60			17			(5	)		7
Ending balance	$	(353	)	$	534		$	(493	)	$	(5	)	$	(317	)
Six Months Ended June 30, 2013
Beginning balance	$	(122	)	$	326		$	(1,081	)	$	—		$	(877	)
Other comprehensive income before reclassifications: gains (losses)		32			81			228			—			341
Amounts reclassified from accumulated other comprehensive income(1): (gains) losses		59			(36	)		30			—			53
Net current-period other comprehensive income (loss)		91			45			258			—			394
Ending balance	$	(31	)	$	371		$	(823	)	$	—		$	(483	)

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

PAGE 25

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

Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Three Months Ended June 30, 2014
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(28	)	Operating revenue
		3		Purchased gas
Interest rate contracts		3		Interest and related charges
		(22	)
Tax		6		Income tax expense
	$	(16	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(13	)	Other income
Impairment		2		Other income
		(11	)
Tax		4		Income tax expense
	$	(7	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(2	)	Other operations and maintenance
Actuarial (gains) losses		17		Other operations and maintenance
		15
Tax		(6	)	Income tax expense
	$	9
Three Months Ended June 30, 2013
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(29	)	Operating revenue
Interest rate contracts		3		Interest and related charges
		(26	)
Tax		9		Income tax expense
	$	(17	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(17	)	Other income
Impairment		3		Other income
		(14	)
Tax		5		Income tax expense
	$	(9	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(6	)
Actuarial (gains) losses		27		Other operations and maintenance
		21
Tax		(11	)	Income tax expense
	$	10
Six Months Ended June 30, 2014
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	241		Operating revenue
		4		Purchased gas
		(13	)	Electric fuel and other energy-related purchases
Interest rate contracts		6		Interest and related charges
		238
Tax		(94	)	Income tax expense
	$	144

PAGE 26

Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(33	)	Other income
Impairment		4		Other income
		(29	)
Tax		11		Income tax expense
	$	(18	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(5	)	Other operations and maintenance
Actuarial (gains) losses		34		Other operations and maintenance
		29
Tax		(12	)	Income tax expense
	$	17
Six Months Ended June 30, 2013
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	55		Operating revenue
		34		Purchased gas
		3		Electric fuel and other energy-related purchases
Interest rate contracts		6		Interest and related charges
		98
Tax		(39	)	Income tax expense
	$	59
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(64	)	Other income
Impairment		5		Other income
		(59	)
Tax		23		Income tax expense
	$	(36	)
		��
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(6	)
Actuarial (gains) losses		56		Other operations and maintenance
		50
Tax		(20	)	Income tax expense
	$	30

PAGE 27

Dominion Gas

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

	Deferred gains and losses on derivatives- hedging activities			Unrecognized pension and other postretirement benefit costs			Total
(millions)
Three Months Ended June 30, 2014
Beginning balance	$	—		$	(60	)	$	(60	)
Other comprehensive income before reclassifications: gains (losses)		(19	)		—			(19	)
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)		3			1			4
Net current-period other comprehensive income (loss)		(16	)		1			(15	)
Ending balance	$	(16	)	$	(59	)	$	(75	)
Three Months Ended June 30, 2013
Beginning balance	$	(30	)	$	(91	)	$	(121	)
Other comprehensive income before reclassifications: gains (losses)		52			13			65
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)		—			1			1
Net current-period other comprehensive income		52			14			66
Ending balance	$	22		$	(77	)	$	(55	)
Six Months Ended June 30, 2014
Beginning balance	$	3		$	(61	)	$	(58	)
Other comprehensive income before reclassifications: gains (losses)		(27	)		(1	)		(28	)
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)		8			3			11
Net current-period other comprehensive income (loss)		(19	)		2			(17	)
Ending balance	$	(16	)	$	(59	)	$	(75	)
Six Months Ended June 30, 2013
Beginning balance	$	(47	)	$	(93	)	$	(140	)
Other comprehensive income before reclassifications: gains (losses)		66			13			79
Amounts reclassified from accumulated other comprehensive income: (gains) losses(1)		3			3			6
Net current-period other comprehensive income		69			16			85
Ending balance	$	22		$	(77	)	$	(55	)

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

PAGE 28

The following table presents Dominion Gas' reclassifications out of AOCI by component:

Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Three Months Ended June 30, 2014
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	2		Operating revenue
		3		Purchased gas
		5
Tax		(2	)	Income tax expense
	$	3
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	1		Other operations and maintenance
		1
Tax		—		Income tax expense
	$	1
Three Months Ended June 30, 2013
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(3	)	Operating revenue
		3		Purchased gas
		—
Tax		—		Income tax expense
	$	—
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	2		Other operations and maintenance
		2
Tax		(1	)	Income tax expense
	$	1
Six Months Ended June 30, 2014
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	7		Operating revenue
		5		Purchased gas
		12
Tax		(4	)	Income tax expense
	$	8
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	4		Other operations and maintenance
		4
Tax		(1	)	Income tax expense
	$	3
Six Months Ended June 30, 2013
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(2	)	Operating revenue
		6		Purchased gas
		4
Tax		(1	)	Income tax expense
	$	3
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	5		Other operations and maintenance
		5
Tax		(2	)	Income tax expense
	$	3

Note 8. Fair Value Measurements

The Companies' fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in Dominion's and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 and Note 6 in Exhibit 99.11(b) to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014. See Note 9 in this report for further information about their derivatives and hedge accounting activities.

The Companies enter into certain physical and financial forwards, futures, options and swaps, 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 and futures contracts. An option model is used to value Level 3 physical and financial options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on

PAGE 29

forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. 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, the original sales prices, and volumes. For Level 3 fair value measurements, forward market prices and implied price volatilities 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 the Companies' quantitative information about Level 3 fair value measurements at June 30, 2014. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input			Range	Weighted Average(1)
Assets:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	19	Discounted Cash Flow		Market Price (per Dth)(5)		(2) - 5		2
FTRs(3)		10	Discounted Cash Flow		Market Price (per MWh)(5)		(1) - 10		1
NGLs(4)		3	Discounted Cash Flow		Market Price (per Gal)(5)		1 - 3		1
Physical and Financial Options:
Natural Gas		4	Option Model		Market Price (per Dth)(5)		3 - 5		4
					Price Volatility	(6)	14% - 32%		24	%
Total assets	$	36
Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	20	Discounted Cash Flow		Market Price (per Dth)(5)		(2) - 5		2
FTRs(3)		3	Discounted Cash Flow		Market Price (per MWh)(5)		(10) - 10		1
NGLs(4)		6	Discounted Cash Flow		Market Price (per Gal)(5)		1 - 3		1
Physical and Financial Options:
Natural Gas		4	Option Model		Market Price (per Dth)(5)		2 - 5		4
					Price Volatility(6)		14% - 32%		25	%
Total liabilities	$	33

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Information represents Dominion Gas’ quantitative information about Level 3 fair value measurements.

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

(6) Represents volatilities unrepresented in published markets.

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)

PAGE 30

Non-recurring Fair Value Measurements

Dominion

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

Dominion Gas

In June 2013, Dominion Gas 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 Gas 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 Gas 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.

Also in June 2013, Dominion Gas recorded an impairment charge of $6 million ($4 million after-tax) in other operations and maintenance expense in its Consolidated Statements of Income, to write off previously capitalized costs following the cancellation of two development projects.

PAGE 31

Recurring Fair Value Measurements

Dominion

The following table presents Dominion’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

	Level 1		Level 2		Level 3		Total
(millions)
At June 30, 2014
Assets:
Derivatives:
Commodity	$	1	$	645	$	36	$	682
Interest rate		—		57		—		57
Investments(1):
Equity securities:
U.S.:
Large cap		2,592		—		—		2,592
Other		6		—		—		6
Non-U.S.:
Large cap		12		—		—		12
Fixed income:
Corporate debt instruments		—		409		—		409
U.S. Treasury securities and agency debentures		446		182		—		628
State and municipal		—		368		—		368
Other		—		7		—		7
Cash equivalents and other		1		91		—		92
Total assets	$	3,058	$	1,759	$	36	$	4,853
Liabilities:
Derivatives:
Commodity	$	1	$	1,113	$	33	$	1,147
Interest rate		—		109		—		109
Total liabilities	$	1	$	1,222	$	33	$	1,256
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

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

PAGE 32

The following table presents the net change in Dominion's assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
(millions)
Beginning balance	$	8		$	9		$	(16	)	$	25
Total realized and unrealized gains (losses):
Included in earnings		(10	)		(10	)		100			2
Included in other comprehensive income (loss)		(1	)		26			3			36
Included in regulatory assets/liabilities		(3	)		(22	)		14			(27	)
Settlements		9			(1	)		(99	)		(26	)
Transfers out of Level 3		—			—			1			(8	)
Ending balance	$	3		$	2		$	3		$	2
The amount of gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date	$	—		$	(4	)	$	1		$	(11	)

PAGE 33

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

	Operating revenue			Purchased Gas			Electric fuel and other energy- related purchases			Total
(millions)
Three Months Ended June 30, 2014
Total gains (losses) included in earnings	$	(1	)	$	(1	)	$	(8	)	$	(10	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		1			(1	)		—			—
Three Months Ended June 30, 2013
Total gains (losses) included in earnings	$	(2	)	$	—		$	(8	)	$	(10	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		(2	)		—			(2	)		(4	)
Six Months Ended June 30, 2014
Total gains (losses) included in earnings	$	(11	)	$	(1	)	$	112		$	100
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		2			(1	)		—			1
Six Months Ended June 30, 2013
Total gains (losses) included in earnings	$	7		$	—		$	(5	)	$	2
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		(10	)		—			(1	)		(11	)

PAGE 34

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 June 30, 2014
Assets:
Derivatives:
Commodity	$	—	$	5	$	10	$	15
Investments(1):
Equity securities:
U.S. Large cap		1,098		—		—		1,098
Fixed income:
Corporate debt instruments		—		221		—		221
U.S. Treasury securities and agency debentures		169		59		—		228
State and municipal		—		185		—		185
Cash equivalents and other		—		28		—		28
Total assets	$	1,267	$	498	$	10	$	1,775
Liabilities:
Derivatives:
Commodity	$	—	$	5	$	3	$	8
Interest rate		—		15		—		15
Total liabilities	$	—	$	20	$	3	$	23
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

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

PAGE 35

The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:

	Three Months Ended June 30,						Six Months Ended June 30,
(millions)	2014			2013			2014			2013
Beginning balance	$	10		$	(3	)	$	(7	)	$	2
Total realized and unrealized gains (losses):
Included in earnings		(9	)		(7	)		111			(4	)
Included in regulatory assets/liabilities		(3	)		(22	)		14			(27	)
Settlements		9			7			(111	)		4
Ending balance	$	7		$	(25	)	$	7		$	(25	)

The gains and losses included in earnings in the Level 3 fair value category were classified in electric fuel and other energy-related purchases in Virginia Power’s Consolidated Statements of Income for the three and six months ended June 30, 2014 and 2013. There were no unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and six months ended June 30, 2014 and 2013.

Dominion Gas

The following table presents Dominion Gas’ assets and liabilities for commodity and interest rate derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:

(millions)	Level 1		Level 2		Level 3		Total
At June 30, 2014
Assets:
Commodity	$	—	$	—	$	3	$	3
Liabilities:
Commodity	$	—	$	7	$	6	$	13
Interest rate		—		19		—		19
Total liabilities	$	—	$	26	$	6	$	32
At December 31, 2013
Assets:
Commodity	$	—	$	—	$	6	$	6
Interest rate		—		34		—		34
Total Assets	$	—	$	34	$	6	$	40
Liabilities:
Commodity	$	—	$	13	$	12	$	25

The following table presents the net change in Dominion Gas’ assets and liabilities for derivatives measured at fair value on a recurring basis and included in the Level 3 fair value category:

	Three Months Ended June 30,						Six Months Ended June 30,
(millions)	2014			2013			2014			2013
Beginning balance	$	(2	)	$	(1	)	$	(6	)	$	(12	)
Total realized and unrealized gains (losses):
Included in earnings		(2	)		3			(7	)		2
Included in other comprehensive income (loss)		(1	)		24			3			35
Settlements		2			(3	)		7			(2	)
Ending balance	$	(3	)	$	23		$	(3	)	$	23

PAGE 36

The gains and losses included in earnings in the Level 3 fair value category were classified in operating revenue in Dominion Gas' Consolidated Statements of Income for the three and six months ended June 30, 2014 and 2013. There were no unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and six months ended June 30, 2014 and 2013.

Fair Value of Financial Instruments

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

	June 30, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	18,883	$	21,103	$	18,396	$	19,887
Junior subordinated notes(3)		1,373		1,392		1,373		1,394
Remarketable subordinated notes(3)		1,082		1,272		1,080		1,192
Subsidiary preferred stock(4)		134		141		257		261
Virginia Power
Long-term debt, including securities due within one year(3)	$	8,730	$	9,970	$	8,032	$	8,897
Preferred stock(4)		134		141		257		261
Dominion Gas
Long-term debt(3)	$	1,199	$	1,236	$	1,198	$	1,169

(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/or premium. At June 30, 2014 and December 31, 2013, includes the valuation of certain fair value hedges associated with fixed rate debt of approximately $54 million and $55 million, respectively.

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

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

PAGE 37

Note 9. Derivatives and Hedge Accounting Activities

The Companies’ accounting policies and objectives and strategies for using derivative instruments are discussed in Note 2 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 and Note 2 in Exhibit 99.11(b) to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014. See Note 8 in this report for further information about fair value measurements and associated valuation methods for derivatives.

Derivative assets and liabilities are presented gross on the Companies’ 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. Dominion Gas’ derivative contracts consist of over-the-counter transactions. 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 the Companies’ 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

Balance Sheet Presentation

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

	June 30, 2014						December 31, 2013
	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	$	57	$	—	$	57	$	137	$	—	$	137
Commodity contracts:
Over-the-counter		195		—		195		240		—		240
Exchange		480		—		480		506		—		506
Total derivatives, subject to a master netting or similar arrangement		732		—		732		883		—		883
Total derivatives, not subject to a master netting or similar arrangement		7		—		7		7		—		7
Total	$	739	$	—	$	739	$	890	$	—	$	890

PAGE 38

			June 30, 2014								December 31, 2013
			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	$	57	$	30	$	—	$	27	$	137	$	—	$	—	$	137
Commodity contracts:
Over-the-counter		195		122		—		73		240		63		—		177
Exchange		480		479		—		1		506		505		—		1
Total	$	732	$	631	$	—	$	101	$	883	$	568	$	—	$	315

	June 30, 2014						December 31, 2013
	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	$	109	$	—	$	109	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		334		—		334		262		—		262
Exchange		809		—		809		838		—		838
Total derivatives, subject to a master netting or similar arrangement		1,252		—		1,252		1,100		—		1,100
Total derivatives, not subject to a master netting or similar arrangement		4		—		4		2		—		2
Total	$	1,256	$	—	$	1,256	$	1,102	$	—	$	1,102

			June 30, 2014								December 31, 2013
			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	$	109	$	30	$	—	$	79	$	—	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		334		122		4		208		262		63		69		130
Exchange		809		479		330		—		838		505		333		—
Total	$	1,252	$	631	$	334	$	287	$	1,100	$	568	$	402	$	130

PAGE 39

Volumes

The following table presents the volume of Dominion’s derivative activity as of June 30, 2014. 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)		68		15
Basis		370		188
Electricity (MWh):
Fixed price		16,045,947		11,120,650
FTRs		73,646,672		—
Capacity (MW)		1,500		16,800
Liquids (Gal)(2)		75,768,000		—
Interest rate	$	1,600,000,000	$	3,925,000,000

(1) Includes options.

(2) Includes NGLs and oil.

Ineffectiveness and AOCI

For the three and six months ended June 30, 2014 and 2013, 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 June 30, 2014:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12  Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(5	)	$	(5	)		22 months
Electricity		(168	)		(141	)		30 months
Other		(1	)		(1	)		23 months
Interest rate		(179	)		(7	)		363 months
Total	$	(353	)	$	(154	)

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

PAGE 40

Fair Value and Gains and Losses on Derivative Instruments

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

	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
June 30, 2014
ASSETS
Current Assets
Commodity	$	163	$	367	$	530
Interest rate		34		—		34
Total current derivative assets(1)		197		367		564
Noncurrent Assets
Commodity		84		68		152
Interest rate		23		—		23
Total noncurrent derivative assets(2)		107		68		175
Total derivative assets	$	304	$	435	$	739
LIABILITIES
Current Liabilities
Commodity	$	419	$	484	$	903
Interest rate		61		—		61
Total current derivative liabilities		480		484		964
Noncurrent Liabilities
Commodity		131		113		244
Interest Rate		48		—		48
Total noncurrent derivative liabilities(3)		179		113		292
Total derivative liabilities	$	659	$	597	$	1,256
December 31, 2013
ASSETS
Current Assets
Commodity	$	49	$	522	$	571
Interest rate		116		—		116
Total current derivative assets(1)		165		522		687
Noncurrent Assets
Commodity		28		154		182
Interest rate		21		—		21
Total noncurrent derivative assets(2)		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(3)		119		155		274
Total derivative liabilities	$	386	$	716	$	1,102

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

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

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

PAGE 41

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

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified from AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended June 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	28
Purchased gas					(3	)
Total commodity	$	(33	)	$	25		$	(4	)
Interest rate(3)		(73	)		(3	)		(8	)
Total	$	(106	)	$	22		$	(12	)
Three Months Ended June 30, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	29
Total commodity	$	131		$	29		$	(8	)
Interest rate(3)		67			(3	)		36
Total	$	198		$	26		$	28
Six Months Ended June 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	(241	)
Purchased gas					(4	)
Electric fuel and other energy-related purchases					13
Total commodity	$	(216	)	$	(232	)	$	(2	)
Interest rate(3)		(119	)		(6	)		(31	)
Total	$	(335	)	$	(238	)	$	(33	)
Six Months Ended June 30, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	(55	)
Purchased gas					(34	)
Electric fuel and other energy-related purchases					(3	)
Total commodity	$	(27	)	$	(92	)	$	(1	)
Interest rate(3)		81			(6	)		52
Total	$	54		$	(98	)	$	51

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

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

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

PAGE 42

	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
	Three Months Ended June 30,						Six Months Ended June 30,
Derivatives not designated as hedging instruments	2014			2013			2014			2013
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	(1	)	$	(6	)	$	(362	)	$	(3	)
Purchased gas		—			(26	)		6			(7	)
Electric fuel and other energy-related purchases		(8	)		(11	)		125			(8	)
Total	$	(9	)	$	(43	)	$	(231	)	$	(18	)

(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.

Virginia Power

Balance Sheet Presentation

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

			June 30, 2014						December 31, 2013
	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		11		—		11		4		—		4
Exchange		1		—		1		1		—		1
Total derivatives, subject to a master netting or similar arrangement		12		—		12		53		—		53
Total derivatives, not subject to a master netting or similar arrangement		3		—		3		—		—		—
Total	$	15	$	—	$	15	$	53	$	—	$	53

			June 30, 2014								December 31, 2013
			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		11		4		—		7		4		4		—		—
Exchange		1		—		—		1		1		—		—		1
Total	$	12	$	4	$	—	$	8	$	53	$	4	$	—	$	49

PAGE 43

			June 30, 2014						December 31, 2013
	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	$	15	$	—	$	15	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		7		—		7		12		—		12
Total derivatives, subject to a master netting or similar arrangement		22		—		22		12		—		12
Total derivatives, not subject to a master netting or similar arrangement		1		—		1		—		—		—
Total	$	23	$	—	$	23	$	12	$	—	$	12

			June 30, 2014								December 31, 2013
			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	$	15	$	—	$	—	$	15	$	—	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		7		4		—		3		12		4		7		1
Total	$	22	$	4	$	—	$	18	$	12	$	4	$	7	$	1

Volumes

The following table presents the volume of Virginia Power’s derivative activity as of June 30, 2014. 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)		17			—
Basis		35			—
Electricity (MWh):
Fixed price		136,800			—
FTRs		73,335,248			—
Capacity (MW)		1,500			16,800
Interest rate	$		—	$	550,000,000

(1) Includes options.

Ineffectiveness

For the three and six months ended June 30, 2014 and 2013, 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.

PAGE 44

Fair Value and Gains and Losses on Derivative Instruments

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

	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
June 30, 2014
ASSETS
Current Assets
Commodity	$	2	$	13	$	15
Total current derivative assets(1)		2		13		15
Total derivative assets	$	2	$	13	$	15
LIABILITIES
Current Liabilities
Commodity	$	3	$	5	$	8
Total current derivative liabilities(2)		3		5		8
Noncurrent Liabilities
Interest rate		15		—		15
Total noncurrent derivatives liabilities(3)		15		—		15
Total derivative liabilities	$	18	$	5	$	23
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(2)		1		11		12
Total derivative liabilities	$	1	$	11	$	12

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

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

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

PAGE 45

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

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified from AOCI to Income		Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended June 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	1
Total commodity	$	—		$	1	$	(4	)
Interest rate(3)		(1	)		—		(8	)
Total	$	(1	)	$	1	$	(12	)
Three Months Ended June 30, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	—
Total commodity	$	(2	)	$	—	$	(8	)
Interest rate(3)		4			—		36
Total	$	2		$	—	$	28
Six Months Ended June 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	6
Total commodity	$	5		$	6	$	(2	)
Interest rate(3)		(4	)		—		(31	)
Total	$	1		$	6	$	(33	)
Six Months Ended June 30, 2013
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	—
Total commodity	$	(1	)	$	—	$	(1	)
Interest rate(3)		6			—		52
Total	$	5		$	—	$	51

(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.

	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
	Three Months Ended June 30,						Six Months Ended June 30,
Derivatives not designated as hedging instruments	2014			2013			2014		2013
(millions)
Derivative Type and Location of Gains (Losses)
Commodity(2)	$	(8	)	$	(6	)	$	111	$	(3	)
Total	$	(8	)	$	(6	)	$	111	$	(3	)

(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.

PAGE 46

Dominion Gas

Balance Sheet Presentation

The tables below present Dominion Gas' derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting.

	June 30, 2014						December 31, 2013
	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	$	—	$	—	$	—	$	34	$	—	$	34
Commodity contracts:
Over-the-counter		3		—		3		6		—		6
Total derivatives, subject to a master netting or similar arrangement	$	3	$	—	$	3	$	40	$	—	$	40

			June 30, 2014						December 31, 2013
			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		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	—	$	—	$	—	$	34	$	—	$	34
Commodity contracts:
Over-the-counter		3		3		—		6		6		—
Total	$	3	$	3	$	—	$	40	$	6	$	34

	June 30, 2014						December 31, 2013
	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	$	19	$	—	$	19	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		13		—		13		25		—		25
Total derivatives, subject to a master netting or similar arrangement	$	32	$	—	$	32	$	25	$	—	$	25

PAGE 47

			June 30, 2014						December 31, 2013
			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		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	19	$	—	$	19	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		13		3		10		25		6		19
Total	$	32	$	3	$	29	$	25	$	6	$	19

Volumes

The following table presents the volume of Dominion Gas’ derivative activity as of June 30, 2014. 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		2		—
Basis		3		—
NGLs (Gal)		60,480,000		—
Interest rate	$	700,000,000	$	100,000,000

Ineffectiveness and AOCI

For the three and six months ended June 30, 2014 and 2013, gains or losses on hedging instruments determined to be ineffective were not material.

The following table presents selected information related to losses on cash flow hedges included in AOCI in Dominion Gas' Consolidated Balance Sheet at June 30, 2014:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Natural Gas	$	(4	)	$	(4	)	6 months
NGLs		(3	)		(3	)	6 months
Interest rate		(9	)		—		363 months
Total	$	(16	)	$	(7	)

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

PAGE 48

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Dominion Gas’ commodity and interest rate 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 June 30, 2014
ASSETS
Current Assets
Commodity	$	3	$	—	$	3
Total current derivative assets(1)		3		—		3
Total derivative assets	$	3	$	—	$	3
LIABILITIES
Current Liabilities
Commodity	$	13	$	—	$	13
Interest rate		16		—		16
Total current derivative liabilities(2)		29		—		29
Noncurrent Liabilities
Interest rate		3		—		3
Total noncurrent derivative liabilities(3)		3		—		3
Total derivative liabilities	$	32	$	—	$	32
At December 31, 2013
ASSETS
Current Assets
Commodity	$	6	$	—	$	6
Interest rate		34		—		34
Total current derivative assets(1)		40		—		40
Total derivative assets	$	40	$	—	$	40
LIABILITIES
Current Liabilities
Commodity	$	25	$	—	$	25
Total current derivative liabilities(2)		25		—		25
Total derivative liabilities	$	25	$	—	$	25

(1) Current derivative assets are presented in other current assets in Dominion Gas’ Consolidated Balance Sheets.

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

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

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The following table presents the gains and losses on Dominion Gas’ 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
(millions)
Three Months Ended June 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	(2	)
Purchased gas					(3	)
Total commodity	$	(3	)	$	(5	)
Interest rate(2)		(28	)		—
Total	$	(31	)	$	(5	)
Three Months Ended June 30, 2013
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	3
Purchased gas					(3	)
Total commodity	$	22		$	—
Interest rate(2)		63			—
Total	$	85		$	—
Six Months Ended June 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	(7	)
Purchased gas					(5	)
Total commodity	$	(2	)	$	(12	)
Interest rate(2)		(42	)		—
Total	$	(44	)	$	(12	)
Six Months Ended June 30, 2013
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	2
Purchased gas					(6	)
Total commodity	$	34		$	(4	)
Interest rate(2)		75			—
Total	$	109		$	(4	)

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

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

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Note 10. Investments

Dominion

Equity and Debt Securities

Rabbi Trust Securities

Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled $109 million and $107 million at June 30, 2014 and December 31, 2013, respectively. Cost method investments held in Dominion’s rabbi trusts totaled $8 million and $10 million at June 30, 2014 and December 31, 2013, 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)
June 30, 2014
Marketable equity securities:
U.S. Large cap	$	1,236	$	1,313	$	—		$	2,549
Marketable debt securities:
Corporate bonds		389		21		(1	)		409
U.S. Treasury securities and agency debentures		618		12		(3	)		627
State and municipal		307		20		(1	)		326
Other		7		—		—			7
Cost method investments		92		—		—			92
Cash equivalents and other(2)		93		—		—			93
Total	$	2,742	$	1,366	$	(5	)(3)	$	4,103
December 31, 2013
Marketable equity securities:
U.S.:
Large cap	$	1,183	$	1,194	$	—		$	2,377
Other		49		23		—			72
Marketable debt securities:
Corporate bonds		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

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

(2) Includes pending sales of securities of $6 million and $11 million at June 30, 2014 and December 31, 2013, respectively.

(3) The fair value of securities in an unrealized loss position was $275 million and $604 million at June 30, 2014 and December 31, 2013, respectively.

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The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at June 30, 2014 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	133
Due after one year through five years		407
Due after five years through ten years		384
Due after ten years		445
Total	$	1,369

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
(millions)
Proceeds from sales	$	244	$	308	$	686	$	862
Realized gains(1)		25		29		63		92
Realized losses(1)		7		10		13		16

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

Other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds for Dominion were not material for the three and six months ended June 30, 2014 and 2013.

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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)
June 30, 2014
Marketable equity securities:
U.S. Large cap	$	530	$	567	$	—		$	1,097
Marketable debt securities:
Corporate bonds		211		10		—			221
U.S. Treasury securities and agency debentures		226		3		(1	)		228
State and municipal		174		11		—			185
Cost method investments		92		—		—			92
Cash equivalents and other(2)		34		—		—			34
Total	$	1,267	$	591	$	(1	)(3)	$	1,857
December 31, 2013
Marketable equity securities:
U.S.:
Large cap	$	506	$	514	$	—		$	1,020
Other		25		11		—			36
Marketable debt securities:
Corporate bonds		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

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

(2) Includes pending sales of securities of $6 million at both June 30, 2014 and December 31, 2013.

(3) The fair value of securities in an unrealized loss position was $114 million and $299 million at June 30, 2014 and December 31, 2013, respectively.

The fair value of Virginia Power’s marketable debt securities at June 30, 2014 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	39
Due after one year through five years		199
Due after five years through ten years		206
Due after ten years		190
Total	$	634

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
(millions)
Proceeds from sales	$	95	$	135	$	299	$	324
Realized gains(1)		10		10		29		26
Realized losses(1)		3		5		6		8

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

Other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds for Virginia Power were not material for the three and six months ended June 30, 2014 and 2013.

Dominion Gas

Equity Method Investment

Dominion Gas accounts for the following investment under the equity method of accounting:

Company	Ownership%			Investment Balance				Description
				June 30, 2014		December 31, 2013
(millions)
Iroquois		24.72	%	$	113	$	105	Gas transmission system
Total				$	113	$	105

Dominion Gas’ equity earnings on this investment totaled $13 million for both the six months ended June 30, 2014 and 2013. Dominion Gas received distributions from this investment of $5 million for both the six months ended June 30, 2014 and 2013. As of June 30, 2014 and December 31, 2013, the carrying amount of Dominion Gas' investment exceeded its share of underlying equity in net assets by approximately $9 million and $8 million, respectively. The differences reflect equity method goodwill and are not being amortized.

Dominion and Dominion Gas

Blue Racer

In December 2012, Dominion formed Blue Racer with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. Blue Racer is an equal partnership between Dominion and Caiman, with Dominion contributing midstream assets and Caiman contributing private equity capital. In June 2014, Blue Racer achieved equalization.

In March 2013, Dominion Gas sold Line TL-404 to an affiliate, that subsequently sold Line TL-404 to Blue Racer for cash proceeds of approximately $47 million. The sale resulted in a gain of approximately $25 million ($14 million after-tax) net of a $2 million write-off of goodwill, and is included in other operations and maintenance expense in both Dominion Gas' and Dominion’s Consolidated Statement of Income.

Dominion NGL Pipelines, LLC was contributed in January 2014 by Dominion to Blue Racer, prior to commencement of service, resulting in an increased equity method investment of $155 million, including $6 million of goodwill allocated from Dominion's goodwill balance to its equity method investment in Blue Racer.

In March 2014, Dominion Gas sold the Northern System to an affiliate, that subsequently sold the Northern System to Blue Racer for consideration of approximately $84 million. Dominion’ Gas’ consideration consisted of $17 million in cash proceeds and the extinguishment of affiliated current borrowings of $67 million and Dominion’s consideration consisted of cash proceeds of approximately $84 million. The sale resulted in a gain of approximately $59 million ($35 million after-tax for Dominion Gas and $34 million after-tax for Dominion) net of a $3 million write-off of goodwill, and is included in other operations and maintenance expense in both Dominion Gas’ and Dominion’s Consolidated Statement of Income.

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Note 11. Regulatory Assets and Liabilities

Regulatory assets and liabilities include the following:

	June 30, 2014		December 31, 2013
(millions)
Dominion
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	131	$	—
Deferred rate adjustment clause costs(2)		40		89
Deferred nuclear refueling outage costs(3)		33		—
Unrecovered gas cost(4)		11		50
Derivatives(5)		5		16
Other		47		62
Regulatory assets-current(6)		267		217
Unrecognized pension and other postretirement benefit costs(7)		683		706
Deferred rate adjustment clause costs(2)		296		287
Income taxes recoverable through future rates(8)		136		155
Deferred cost of fuel used in electric generation(1)		123		1
Derivatives(5)		52		16
Other		85		63
Regulatory assets-non-current		1,375		1,228
Total regulatory assets	$	1,642	$	1,445
Regulatory liabilities:
PIPP(9)	$	75	$	76
Other		42		52
Regulatory liabilities-current(10)		117		128
Provision for future cost of removal and AROs(11)		1,052		1,028
Decommissioning trust(12)		766		693
Deferred cost of fuel used in electric generation(1)		7		90
Other		186		190
Regulatory liabilities-non-current		2,011		2,001
Total regulatory liabilities	$	2,128	$	2,129
Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	131	$	—
Deferred nuclear refueling outage costs(3)		33		—
Deferred rate adjustment clause costs(2)		28		62
Derivatives(5)		5		16
Other		45		50
Regulatory assets-current(6)		242		128
Deferred rate adjustment clause costs(2)		228		227
Deferred cost of fuel used in electric generation(1)		123		1
Income taxes recoverable through future rates(8)		105		124
Derivatives(5)		52		16
Other		53		49
Regulatory assets-non-current		561		417
Total regulatory assets	$	803	$	545
Regulatory liabilities:
Other	$	28	$	41
Regulatory liabilities-current(10)		28		41

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Provision for future cost of removal(11)		828		807
Decommissioning trust(12)		766		693
Deferred cost of fuel used in electric generation(1)		7		90
Other		6		7
Regulatory liabilities-non-current		1,607		1,597
Total regulatory liabilities	$	1,635	$	1,638
Dominion Gas
Regulatory assets:
Deferred rate adjustment clause costs(2)	$	12	$	27
Unrecovered gas costs(4)		1		40
Bad debt tracker(13)		—		11
Other		—		1
Regulatory assets-current(6)		13		79
Unrecognized pension and other postretirement benefit costs(7)		188		194
Deferred rate adjustment clause costs(2)		68		59
Income taxes recoverable through future rates(8)		24		24
Other postretirement benefit costs(14)		—		7
Other		24		1
Regulatory assets-non-current		304		285
Total regulatory assets	$	317	$	364
Regulatory liabilities:
PIPP(9)	$	75	$	76
Other		10		3
Regulatory liabilities-current(10)		85		79
Provision for future cost of removal and AROs(11)		178		177
Unrecognized pension and other postretirement benefit costs(7)		16		18
Other		13		8
Regulatory liabilities-non-current(15)		207		203
Total regulatory liabilities	$	292	$	282

(1) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power’s generation operations.

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

(3) Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, but in no case for more than 18 months.

(4) Reflects unrecovered gas costs at regulated gas operations, which are recovered through filings with the applicable regulatory authority.

(5) 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.

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

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

(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) Under PIPP, eligible customers can make reduced payments 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.

(10) Current regulatory liabilities are presented in other current liabilities in the Companies’ Consolidated Balance Sheets.

(11) 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.

(12) Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related AROs.

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(13) Represents East Ohio’s deferrals for the UEX Rider which are recovered through rates which are filed annually. Most of East Ohio’s bad debt expense is recovered either through the UEX Rider or the PIPP Rider.

(14) Primarily reflects costs recognized in excess of amounts included in regulated rates charged by Dominion Gas’ regulated gas operations before rates were updated to reflect a change in accounting method for other postretirement benefit costs.

(15) Noncurrent regulatory liabilities are presented in other deferred credits and other liabilities in Dominion Gas’ Consolidated Balance Sheets.

At June 30, 2014, approximately $136 million of Dominion’s, $107 million of Virginia Power’s and $18 million of Dominion Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. These expenditures are expected to be recovered within the next year.

Note 12. Regulatory Matters

Regulatory Matters Involving Potential Loss Contingencies

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

In March 2014, FERC issued an order excluding from Virginia Power’s transmission rates for wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable for non-Virginia wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities because the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to benefit the citizens of Virginia. The order is retroactively effective as of March 2010 and will cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC determined that there was not sufficient evidence on the record to determine the magnitude of the underground increment and ordered a hearing to determine the appropriate amount of undergrounding cost to

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be allocated to each wholesale transmission customer in Virginia. The hearing has been held in abeyance pending the outcome of an ongoing settlement proceeding, as ordered by FERC. While Virginia Power cannot predict the outcome of the hearing and settlement proceedings, it is not expected to have a material effect on results of operations.

Other Regulatory Matters

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 13 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013, Note 12 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, Note 12 in Exhibit 99.11(b) to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014 and Note 11 in Exhibit 99.11(c) to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014.

Virginia Regulation

Virginia Fuel Expenses

In May 2014, Virginia Power submitted its annual fuel factor filing to the Virginia Commission to recover an estimated $1.9 billion in Virginia jurisdictional projected fuel expense for the rate year beginning July 1, 2014. Virginia Power also offered to defer recovery of 50% of its total estimated $268 million jurisdictional deferred fuel balance to the 2015-2016 fuel year, thereby recovering $134 million of its jurisdictional deferred fuel balance for the rate year beginning July 1, 2014. In May 2014, the Virginia Commission issued an order approving the increased fuel rate on an interim basis effective July 1, 2014. This case is pending.

Rate Adjustment Clauses

Below are developments to significant riders associated with various Virginia Power projects:

• The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2014,Virginia Power proposed an approximately $13 million revenue requirement for the rate year beginning April 1, 2015. This case is pending.

• The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2014, Virginia Power proposed an approximately $244 million revenue requirement for the rate year beginning April 1, 2015. This case is pending.

• The Virginia Commission previously approved Rider W in conjunction with Warren County. In May 2014, Virginia Power proposed an approximately $135 million revenue requirement for the rate year beginning April 1, 2015. This case is pending.

• The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In June 2014, Virginia Power proposed an approximately $84 million revenue requirement for the rate year beginning April 1, 2015. This case is pending.

• The Virginia Commission previously approved Rider BW in connection with Brunswick County. In July 2014, the Virginia Commission approved an approximately $85 million revenue requirement for the rate year beginning September 1, 2014, which represents an approximately $41 million increase over the previous year.

• The Virginia Commission previously approved Riders C1A and C2A in connection with various DSM programs. In April 2014, the Virginia Commission approved an approximately $1 million revenue requirement for Rider C1A, and an approximately $30 million revenue requirement for Rider C2A, for the rate year beginning May 1, 2014, which represents an approximately $4 million increase to the total revenue requirement for both Riders over the previous year. The Virginia Commission also approved a combined spending cap of approximately $72 million, inclusive of lost revenues, for three new DSM programs.

• The Virginia Commission previously approved Rider T1. In July 2014, the Virginia Commission approved an approximately $538 million revenue requirement for the rate year beginning September 1, 2014, which represents an approximately $134 million increase over the previous year.

Electric Transmission Projects

In April 2014, the Virginia Commission issued an order granting Virginia Power a CPCN to rebuild within existing rights-of-way its 500-kV Loudoun-Pleasant View transmission line in Loudoun County at an estimated cost of approximately $31 million.

North Anna COL

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. In April 2013, Virginia Power decided to replace the reactor design previously selected for a potential unit with ESBWR technology. 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. The COL is expected in 2016. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

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In February 2014, BREDL filed a petition with the NRC seeking to stay final decision making in the COL proceeding until a rulemaking petition filed by a number of environmental groups several weeks earlier is resolved. The suspension request and underlying petition for rulemaking are based on analyses of the consequences of a spent fuel pool fire, but none of the analyses relates specifically to the ESBWR design. The NRC denied the petition in July 2014. Substantially identical suspension petitions and contentions were filed by various intervenor groups in other licensing proceedings pending before the NRC. In March 2014, BREDL filed a motion to reopen the COL proceeding on seismic issues under a previous ruling of the ASLB. No other issues were raised by BREDL in its filing. In June 2014, the ASLB denied BREDL’s motion to reopen the COL proceeding. BREDL did not appeal the ASLB’s decision, and under a previous ruling of the NRC, the contested portion of the COL proceeding remains terminated.

North Anna and Offshore Wind Legislation

In April 2014 legislation was enacted in Virginia that permits Virginia Power to recover 70% of the costs previously deferred or capitalized related to the development of a third nuclear unit located at North Anna and offshore wind facilities through December 31, 2013 as part of the 2013 and 2014 base rates. Virginia Power has deferred or capitalized costs totaling approximately $577 million for these projects as of December 31, 2013, substantially all of which relate to North Anna. For the 70% portion of these previously deferred or capitalized costs allocable to customers in Virginia, Virginia Power will recognize such amounts that are now recoverable in 2013 and 2014 base rates as charges against net income beginning in the second quarter of 2014 and for the remainder of the year. In the second quarter of 2014, Virginia Power recognized a $287 million ($191 million after-tax) charge against income representing the cumulative recovery of costs from January 2013 through June 2014 and will recognize additional charges of approximately $87 million ($57 million after-tax) ratably during the remainder of 2014. The remaining deferred or capitalized costs, as well as costs incurred after December 31, 2013, continue to be eligible for inclusion in a future rate adjustment clause.

North Carolina Regulation

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 were appealed to the North Carolina Supreme Court by multiple parties. In June 2014, the Supreme Court of North Carolina issued an opinion reversing the portion of the North Carolina Commission’s December 2012 order from Virginia Power’s 2012 base rate case approving a 10.2% ROE for Virginia Power, and remanding the case to the North Carolina Commission for additional findings of fact in light of a 2013 opinion issued after the North Carolina Commission’s order. This case is pending.

Ohio Regulation

PIR Program

In 2008, East Ohio began PIR, aimed at replacing more than 20% of its pipeline. In May 2014, PIR cost recovery rates became effective as approved by the Ohio Commission in April 2014. The approval includes a revenue requirement of $89 million, which represents an approximately $22 million increase over the previous year.

AMR Program

In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. In May 2014, AMR cost recovery rates became effective as approved by the Ohio Commission in April 2014. The approval includes a revenue requirement of $8 million, which represents an approximately $3 million increase over the previous year.

House Bill 95

Ohio enacted utility reform legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future.

In July 2014, the Ohio Commission approved East Ohio’s application requesting authority to implement a capital expenditure program for 2014 capital expenditures totaling $110 million.

PIPP Plus Program

Under the Ohio PIPP Plus Program, eligible customers can make reduced payments 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 2014, East Ohio’s annual update of the PIPP Rider was automatically approved by the Ohio Commission after a 45-day waiting period from the date of the filing. The increased rider rate reflects the refund over the next year of an over-recovery of accumulated arrearages of approximately $82 million as of March 31, 2014, net of projected deferred program costs of approximately $96 million for the period from April 2014 through June 2015.

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UEX Rider

East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In July 2014, the Ohio Commission approved a decrease to East Ohio’s UEX Rider, which reflects the elimination of the over-recovered balance of accumulated bad debt expense of approximately $8 million as of March 31, 2014, and recovery of prospective bad debt expense projected to total approximately $25 million for the twelve-month period from April 2014 to March 2015.

Note 13. Variable Interest Entities

As discussed in Note 15 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 and Note 14 in Exhibit 99.11(b) to Dominion Gas' Current Report on Form 8-K dated June 26, 2014, certain variable pricing terms in some of the Companies’ contracts cause them to be considered variable interests in the counterparties.

Virginia Power has long-term power and capacity contracts with four non-utility generators with an aggregate summer generation capacity of approximately 870 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power's knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power's determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power's contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $807 million as of June 30, 2014. Virginia Power paid $55 million and $53 million for electric capacity and $33 million and $26 million for electric energy to these entities in the three months ended June 30, 2014 and 2013, respectively. Virginia Power paid $111 million and $108 million for electric capacity and $87 million and $46 million for electric energy to these entities in the six months ended June 30, 2014 and 2013, respectively.

Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of approximately $106 million and and $26 million for the three months ended June 30, 2014, $83 million and $25 million for the three months ended June 30, 2013, $214 million and $52 million for the six months ended June 30, 2014, and $160 million and $51 million for the six months ended June 30, 2013, respectively. Virginia Power and Dominion Gas determined that each is not the most closely associated entity with DRS and therefore neither is the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power and Dominion Gas. Virginia Power and Dominion Gas have no obligation to absorb more than their allocated shares of DRS costs.

Note 14. Significant Financing Transactions

Credit Facilities and Short-term Debt

The Companies 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.

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Dominion

At June 30, 2014, Dominion’s commercial paper and letters of credit outstanding, as well as its capacity available under credit facilities, were as follows:

	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility(1)	$	4,000	$	2,848	$	—	$	1,152
Joint revolving credit facility(2)		500		232		115		153
Total	$	4,500	$	3,080	$	115	$	1,305

(1) In May 2014, this credit facility was amended and restated. The facility limit was increased from $3 billion to $4 billion and the maturity date was extended from September 2018 to April 2019. 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) In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

Virginia Power

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

At June 30, 2014, 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 and Dominion Gas were as follows:

	Facility Sub-limit(3)		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Sub-limit Capacity Available(3)
(millions)
Joint revolving credit facility(1)	$	1,000	$	1,091	$	—	$	(91	)
Joint revolving credit facility(2)		250		232		18		—
Total	$	1,250	$	1,323	$	18	$	(91	)

(1) In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.

(2) In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. 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) On June 30, 2014, Virginia Power’s facility sub-limit was exceeded; however, Virginia Power retained ongoing access to its short-term demand note with Dominion as discussed in Note 17 and remained in compliance with its debt covenants. Effective July 10, 2014, Virginia Power increased its sub-limit under the $4 billion credit facility from $1.0 billion to $1.25 billion bringing its total sub-limit to $1.5 billion.

In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility. In May 2014, this credit facility was amended and restated and the maturity date was extended from September 2018 to April 2019. As of June 30, 2014, this facility supports approximately $119 million of certain variable rate tax-exempt financings of Virginia Power.

Dominion Gas

Dominion Gas’ short-term financing is supported by the two joint revolving credit facilities discussed above with Dominion and Virginia Power, to which Dominion Gas was added as a borrower in May 2014.

Dominion Gas’ current sub-limit under the $4 billion credit facility is $500 million, all of which is currently available, and can be increased or decreased multiple times per year, up to a maximum of $1 billion. Dominion Gas’ current sub-limit under the $500 million credit facility is $0 and can also be increased or decreased multiple times per year. The maturity date for both facilities is April 2019.

Long-term Debt

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.

In March 2014, Dominion issued $400 million of 1.25% senior notes that mature in 2017.

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In April 2014, Virginia Power redeemed the $10 million 2.5% and the $30 million 2.5% Industrial Development Authority of the Town of Louisa, Virginia Solid Waste and Sewage Disposal Revenue Bonds, Series 1997A and 2000A, that would otherwise have matured in April 2022 and September 2030, respectively.

In June 2014, Dominion Gas commenced an offer to exchange $1.2 billion principal amount of unsecured senior notes that were issued in a private placement in October 2013. The exchange offer satisfies Dominion Gas' obligations under a registration rights agreement entered into in connection with the issuance of the Dominion Gas 2013 Senior Notes. The exchange offer does not represent a new financing transaction and there will be no proceeds to Dominion Gas when the offer settles, which is expected to occur in August 2014.

Convertible Securities

At June 30, 2014, Dominion had $36 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominion’s common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. The conversion rate is subject to adjustment upon certain events such as subdivisions, splits, combinations of common stock or the issuance to all common stock holders of certain common stock rights, warrants or options and certain dividend increases. As of June 30, 2014, the conversion rate had been adjusted, primarily due to individual dividend payments above the level paid at issuance, to 30.1180 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $33.20. If the outstanding notes as of June 30, 2014 were all converted, it would result in the issuance of approximately 550,000 additional shares of common stock.

The senior notes are eligible for conversion during any calendar quarter when the closing price of Dominion’s common stock was equal to or higher than 120% of the conversion price for at least 20 out of the last 30 consecutive trading days of the preceding quarter, the notes are called for redemption by Dominion and upon the occurrence of certain other conditions. During the first and second quarters of 2014, the senior notes were eligible for conversion and approximately $7 million of the notes were converted by holders into $7 million of common stock. The senior notes are eligible for conversion during the third quarter of 2014.

Preferred Stock

In February 2014, Virginia Power provided irrevocable notice to redeem all 1,250,000 outstanding shares of its Flex MMP Stock. In March 2014, Virginia Power redeemed the stock at a price of $100 per share plus accumulated and unpaid dividends at a rate reset in March 2011 of 6.12%. Dividends ceased accumulating on the stock upon payment of the redemption price, thus the rate was not reset in March 2014.

Issuance of Common Stock

Dominion maintains Dominion Direct^® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. In January 2014, Dominion began purchasing its common stock on the open market for these plans. In April 2014, Dominion began issuing new common shares for these direct stock purchase plans.

Remarketable Subordinated Notes

In July 2014, Dominion issued $1 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbol DCUC.

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.

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Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion will issue between 11.5 million and 14.3 million shares of its common stock in July 2017. A total of 17.75 million shares of Dominion’s common stock has been reserved for issuance in connection with the stock purchase contracts.

Selected information about Dominion’s 2014 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 Settlement Date		RSN Maturity Date
(millions, except interest rates)
7/1/2014		20	$	982.0	$	1,000.0		1.500	%		4.875	%		7/1/2017		7/1/2020

Note 15. Commitments and Contingencies

As a result of issues generated in the ordinary course of business, the Companies are involved in legal proceedings before various courts and are periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, and/or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and 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 the Companies’ financial position, liquidity or results of operations.

Environmental Matters

The Companies 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 the Companies’ facilities are subject to the CAA’s permitting and other requirements.

The EPA established CAIR with the intent to require significant reductions in SO₂ and NO_Xemissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO₂ and NO_xemissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO₂ and NO_x emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NO_x emissions caps, NO_x emissions caps during the ozone season (May 1 through September 30) and annual SO₂ emission caps with differing requirements for two groups of affected states.

Following numerous petitions by industry participants for review and motions for stay, the U.S. Court of Appeals for the D.C. Circuit issued a ruling in December 2011 to stay CSAPR pending judicial review. A 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 April 2014, the U.S. Supreme Court issued a decision upholding CSAPR by reversing and remanding the D.C. Circuit’s decision vacating the rule. The decision, however, did not lift the stay of CSAPR, and CAIR continues to remain in effect. In June 2014, the EPA filed a motion asking the U.S. Court of Appeals for the D.C. Circuit to lift the stay of CSAPR. Further, the EPA asked the court to toll the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets (which would have gone into effect in 2012 and 2013) would apply in 2015 and 2016, and Phase 2 emissions budgets would apply in 2017 and beyond. The cost to comply is not expected to be material. Future outcomes of any additional litigation and/or any action to issue a revised rule could affect the assessment regarding cost of compliance.

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In May 2012, the EPA issued final designations for the 75-ppb ozone air quality standard. A number of the Companies’ facilities are located within 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 August 2010, the EPA issued revised National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. The rule was amended in March 2011 and January 2013. The rule establishes emission standards for control of hazardous air pollutants for engines at smaller facilities, known as area sources. As a result of these regulations, Dominion Gas installed emissions controls on several compressor engines. Dominion Gas has spent approximately $2 million to date and is evaluating further expenditures. Dominion Gas is unable to estimate the additional potential impacts on results of operations, financial condition and/or cash flows related to this matter.

In August 2012, the EPA issued the first NSPS impacting the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of volatile organic chemical emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. Compliance with these rules is required for installations and wells constructed or reconstructed after August 23, 2011. The cost to comply with the NSPS will depend on the number of new wells and new equipment installations subject to the rule; therefore, Dominion Gas is unable to estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.

Water

The CWA, as amended, is a comprehensive program utilizing 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 program at their operating facilities.

In May 2014, the EPA published final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. 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 are currently evaluating the need or potential for entrainment controls under the final 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. While the impacts of this rule could be material to Dominion’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.

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.

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From time to time, Dominion, Virginia Power, or Dominion Gas 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, Virginia Power, or Dominion Gas 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, and 12 of which pertain to Dominion Gas. 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 the Companies 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. Virginia Power 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. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.

Climate Change Legislation and Regulation

In October 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the D.C. Circuit Court's June 2012 decision upholding the EPA’s regulation of GHG emissions from stationary sources under the CAA's permitting programs. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the EPA’s ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. Due to uncertainty regarding what actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the Court ruling, the Companies cannot predict the impact to operations at this time.

In July 2011, the EPA signed a final rule deferring the need for PSD 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 PSD and Title V applicability thresholds, including those for the application of BACT. 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.

Legal Matters

Dominion Gas is the defendant in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, Dominion Gas is unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.

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Following the completion of the Appalachian Gateway Project in 2012, DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DTI filed a complaint in U.S. District Court, Eastern District of Virginia for breach of contract, accounting and declaratory relief. The contractor filed a motion to dismiss, or in the alternative, a motion to transfer venue to Pennsylvania and/or West Virginia, where the pipelines were constructed. DTI filed an opposition to the contractor’s motion in August 2013. In November 2013, the court granted the contractor’s motion on the basis that DTI must first comply with the dispute resolution process. Pursuant to the ruling, DTI intends to mediate the matter. This case is pending. DTI has accrued a liability of approximately $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.

Cove Point

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 May 2014, the Maryland Commission granted a CPCN authorizing the construction of such generating station. The CPCN is contingent upon Cove Point receiving FERC approval for the liquefaction project and will obligate Cove Point to make payments over time totaling approximately $48 million to the Maryland Strategic Energy Investments Fund and Maryland low income energy assistance programs. In June 2014, a party filed a notice of petition for judicial review of the CPCN with the Circuit Court for Baltimore City in Maryland. This matter is currently pending.

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. The updated seismic analyses are complete and Dominion and Virginia Power are discussing with the NRC any further actions that will be required for their plants. 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.

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 Dominion’s and Virginia Power's contracts with the DOE. Dominion and Virginia Power have previously received damages award payments and settlement payments related to these contracts and have 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.

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In the second quarter of 2014, the government formally accepted offers of settlement from Virginia Power and Dominion to resolve claims for damages incurred at North Anna and Surry in the amount of approximately $27 million for the period of January 1, 2011 through December 31, 2012 and at Millstone in the amount of approximately $17 million for the period July 1, 2012 through June 30, 2013. Payment is expected by the third quarter of 2014. Dominion expects that the government will formally accept an offer of settlement for resolution of claims incurred at Kewaunee in the amount of approximately $5 million for the period January 1 through December 31, 2013, with payment expected in the third or fourth quarter of 2014.

By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone plants have been extended to provide for periodic payments for damages incurred through December 31, 2016. Possible extension of the Kewaunee settlement agreement is being evaluated.

Dominion and Virginia Power 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 $92 million and $79 million at June 30, 2014 and December 31, 2013, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $60 million and $50 million at June 30, 2014 and December 31, 2013, respectively.

Pursuant to a November 2013 decision of the U.S Court of Appeals for the D.C. 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 processes specified in the Nuclear Waste Policy Act for adjustment of the fee have been completed, and as of May 16, 2014, Dominion and Virginia Power are no longer required to pay the waste fee. In 2014, Dominion and Virginia Power recognized fees of $16 million and $10 million, respectively.

Dominion and Virginia Power will continue to manage their spent fuel until it is accepted by the DOE.

Guarantees

Dominion

At June 30, 2014, 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 June 30, 2014, Dominion’s exposure under these guarantees was $54 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 June 30, 2014, Dominion’s maximum remaining cumulative exposure under these equity funding agreements was $80 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 June 30, 2014, Dominion had issued the following subsidiary guarantees:

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	27	$	27
Commodity transactions(3)		3,040		468
Nuclear obligations(4)		236		91
Cove Point(5)		335		—
Solar(6)		169		397
Other(7)		521		84
Total	$	4,328	$	1,067

(1) Represents the estimated portion of the guarantee’s stated limit that is utilized as of June 30, 2014 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.

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(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, Dominion Gas 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 certain expenses of Millstone (in the event of a prolonged outage) and Kewaunee, respectively, 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 EPC contract for new liquefaction facilities. Includes certain guarantees that do not have stated limits.

(6) Includes guarantees to facilitate the development of solar projects including guarantees to support the issuance of limited notice to proceed and full notice to proceed under EPC agreements as well as to support payment obligations under module supply agreements. Includes certain guarantees that do not have stated limits. Also includes a guarantee entered into by DEI on behalf of a subsidiary to facilitate the acquisition and development of a solar project.

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

Surety Bonds and Letters of Credit

As of June 30, 2014, Dominion had purchased $129 million of surety bonds, including $60 million at Virginia Power and $31 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $115 million, including $18 million at Virginia Power, to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

Note 16. Credit Risk

The Companies’ accounting policies for credit risk are discussed in Note 23 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 and Note 19 in Exhibit 99.11(b) to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014.

At June 30, 2014, Dominion’s credit exposure totaled $122 million. Of this amount, investment grade counterparties, including those internally rated, represented 59%. No counterparty exposure exceeded 10% of Dominion’s total exposure.

Credit-Related Contingent Provisions

The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of June 30, 2014 and December 31, 2013, Dominion would have been required to post an additional $79 million and $146 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 approximately $5 million and $76 million in collateral at June 30, 2014 and December 31, 2013, respectively, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of June 30, 2014 and December 31, 2013 was $161 million and $169 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and Dominion Gas were not material as of June 30, 2014 and December 31, 2013. See Note 9 for further information about derivative instruments.

Dominion Gas

In the second quarter of 2014, DTI provided service to 234 customers with approximately 94% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 42% of the total storage and transportation revenue and the 30 largest provided approximately 75% of the total storage and transportation revenue. Approximately 97% of the transmission capacity under contract on DTI’s pipeline is subscribed with long-term contracts (two years or greater). The remaining 3% is contracted on a year-to-year basis. Less than 1% of firm transportation capacity is currently unsubscribed. All storage services are subscribed under long-term contracts.

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East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates established by the Ohio Commission. Approximately 98% of East Ohio revenues are derived from its jurisdictional gas services. East Ohio’s bad debt risk is mitigated by the regulatory framework established by the Ohio Commission. See Note 12 for further information about Ohio’s PIPP and UEX Riders that mitigate East Ohio’s overall credit risk.

Note 17. Related Party Transactions

Virginia Power and Dominion Gas engage in related party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s and Dominion Gas’ 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 and Dominion Gas are included in Dominion’s consolidated federal income tax return. A discussion of significant related party transactions follows.

Virginia Power

Transactions with Affiliates

Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps, to manage commodity price risk associated with purchases of natural gas. See Note 9 for more information. As of June 30, 2014 and December 31, 2013, Virginia Power’s derivative assets and liabilities with affiliates were not material. Virginia Power participates in certain Dominion benefit plans. In Virginia Power’s Consolidated Balance Sheets at June 30, 2014 and December 31, 2013, amounts due to Dominion associated with these benefit plans included in other deferred credits and other liabilities were $182 million and $147 million, respectively, and amounts due from Dominion at June 30, 2014 included in other deferred charges and other assets were $16 million.

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:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
(millions)
Commodity purchases from affiliates	$	113	$	105	$	315	$	190
Services provided by affiliates(1)		106		106		214		202
Services provided to affiliates		6		5		11		10

(1) Amounts are subject to capitalization.

Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. There were $97 million in short-term demand note borrowings from Dominion as of December 31, 2013. There were no short-term demand note borrowings as of June 30, 2014. Virginia Power had no outstanding borrowings, net of repayments under the Dominion money pool for its nonregulated subsidiaries as of June 30, 2014 and December 31, 2013. Interest charges related to Virginia Power’s borrowings from Dominion were not material for the three and six months ended June 30, 2014 and 2013.

Dominion Gas

Transactions with Affiliates

Dominion Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Gas provides transportation and storage services to affiliates. Dominion Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of June 30, 2014 and December 31 2013, all of Dominion Gas’ commodity derivatives were with affiliates. See Note 9 for more information. Dominion Gas participates in certain Dominion benefit plans as described in Note 18. See Note 10 for information regarding sales of assets to an affiliate.

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	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
(millions)
Purchases of natural gas and transportation and storage services from affiliates	$	6	$	7	$	8	$	9
Sales of natural gas and transportation and storage services to affiliates		21		22		46		44

DRS and affiliates provide certain administrative and technical services to Dominion Gas. Dominion Gas provides certain services to affiliates, including technical services. The costs of these services follow:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
(millions)
Services provided by affiliates(1)	$	25	$	33	$	51	$	59
Goods and services provided by Dominion Gas to affiliates		3		5		6		9
Goods and services provided by Dominion Gas to related parties		7		2		16		5

(1) Amounts are subject to capitalization.

The following table presents affiliated and related party activity reflected in Dominion Gas’ Consolidated Balance Sheets:

	June 30, 2014		December 31, 2013
(millions)
Customer receivables from related parties	$	6	$	3
Imbalances receivable from affiliates(1)		6		6
Imbalances payable to affiliates(2)		1		1
Affiliated notes receivable(3)		7		5

(1) Amounts are presented in other current assets in Dominion Gas’ Consolidated Balance Sheets.

(2) Amounts are presented in other current liabilities in Dominion Gas’ Consolidated Balance Sheets.

(3) Amounts are presented in other deferred charges and other assets in Dominion Gas’ Consolidated Balance Sheets.

Dominion Gas’ borrowings under the IRCA with Dominion totaled $1.5 billion as of June 30, 2014 and $1.3 billion as of December 31, 2013. Interest charges related to Dominion Gas’ total borrowings from Dominion were $1 million and $11 million for the three months ended June 30, 2014 and 2013, respectively, and $2 million and $21 million for the six months ended June 30, 2014 and 2013, respectively. Dominion Gas capitalized $5 million and $8 million of interest charges to property, plant and equipment for the three and six months ended June 30, 2013, respectively.

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Note 18. Employee Benefit Plans

Dominion

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

	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
(millions)
Three Months Ended June 30,
Service cost	$	28		$	34		$	8		$	12
Interest cost		73			67			16			18
Expected return on plan assets		(125	)		(115	)		(27	)		(22	)
Amortization of prior service cost (credit)		1			1			(7	)		(3	)
Amortization of net actuarial loss		28			44			1			2
Settlements and curtailments(1)		—			(2	)		—			(15	)
Net periodic benefit cost (credit)	$	5		$	29		$	(9	)	$	(8	)
Six Months Ended June 30,
Service cost	$	57		$	69		$	16		$	24
Interest cost		145			133			33			37
Expected return on plan assets		(250	)		(229	)		(55	)		(44	)
Amortization of prior service cost (credit)		2			2			(14	)		(6	)
Amortization of net actuarial loss		56			90			1			4
Settlements and curtailments(1)		—			(2	)		—			(15	)
Net periodic benefit cost (credit)	$	10		$	63		$	(19	)	$	—

(1) Relate primarily to the decommissioning of Kewaunee.

Employer Contributions

During the six months ended June 30, 2014, Dominion made no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs during the remainder of 2014.

Dominion Gas

Dominion Gas participates in certain Dominion benefit plans as described in Note 17 in Exhibit 99.11(b) to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014. At June 30, 2014 and December 31, 2013, Dominion Gas’ amounts due from Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $595 million and $577 million, respectively. At June 30, 2014 and December 31, 2013, Dominion Gas’ amounts due to Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred credits and other liabilities in the Consolidated Balance Sheets were $11 million and $14 million, respectively.

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The components of Dominion Gas’ provision for net periodic benefit credit for employees represented by collective bargaining units were as follows:

	Pension Benefits						Other Postretirement Benefits
	2014			2013			2014			2013
(millions)
Three Months Ended June 30,
Service cost	$	3		$	4		$	2		$	2
Interest cost		7			7			3			3
Expected return on plan assets		(28	)		(27	)		(6	)		(4	)
Amortization of prior service credit		—			—			(1	)		(1	)
Amortization of net actuarial loss		4			7			—			—
Net periodic benefit credit	$	(14	)	$	(9	)	$	(2	)	$	—
Six Months Ended June 30,
Service cost	$	6		$	7		$	3		$	4
Interest cost		14			13			6			6
Expected return on plan assets		(57	)		(52	)		(11	)		(9	)
Amortization of prior service credit		—			—			(1	)		(2	)
Amortization of net actuarial loss		9			14			—			1
Net periodic benefit credit	$	(28	)	$	(18	)	$	(3	)	$	—

Employer Contributions

During the six months ended June 30, 2014, Dominion Gas made no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion Gas expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs, for both employees represented by collective bargaining units and employees not represented by collective bargaining units, during the remainder of 2014.

Note 19. Operating Segments

The Companies 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	Dominion Gas
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	X
Dominion Energy	Gas transmission and storage(1)	X		X
	Gas distribution and storage	X		X
	Gas gathering and processing	X		X
	LNG import and storage	X

(1) Includes remaining producer services activities.

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

Dominion

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 or sold. 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 January 2014, Dominion announced it would exit the electric retail energy marketing business. Dominion completed the sale in March 2014. As a result, the earnings impact from the electric retail energy marketing business has been included in the Corporate and Other Segment of Dominion for 2014 first quarter results of operations.

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In the second quarter of 2013, Dominion commenced a repositioning 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 repositioning was completed in the first quarter of 2014 and 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 for 2014.

In the six months ended June 30, 2014, Dominion reported an after-tax net expense of $430 million for specific items in the Corporate and Other segment, with $402 million of these net expenses attributable to its operating segments. In the six months ended June 30, 2013, Dominion reported an after-tax net expense of $134 million for specific items in the Corporate and Other segment, with $131 million of these net expenses attributable to its operating segments.

The net expense for specific items in 2014 primarily related to the impact of the following items:

• A $319 million ($193 million after-tax) net loss related to the producer services business discussed above, attributable to Dominion Energy;

• A $287 million ($191 million after-tax) charge associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, attributable to Dominion Generation; and

• A $47 million ($33 million after-tax) net loss related to the electric retail energy marketing business discussed above, including a $147 million ($90 million after-tax) loss from normal operations, partially offset by a $100 million ($57 million after-tax) gain on sale net of a $31 million write-off of goodwill, attributable to Dominion Generation.

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

• A $118 million ($69 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 pending sale, impairment charges of $48 million ($28 million after-tax), and a $6 million ($3 million after-tax) loss from operations, attributable to Dominion Generation;

• A $107 million ($57 million after-tax) net loss, including a $55 million ($33 million after-tax) impairment charge related to certain natural gas infrastructure assets and a $52 million ($24 million after-tax) loss related to the producer services business discussed above, attributable to Dominion Energy; and

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

• A $51 million ($31 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.

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

	DVP(1)		Dominion Generation(1)		Dominion Energy		Corporate and Other			Adjustments/ Eliminations(1)			Consolidated Total
(millions)
Three Months Ended June 30, 2014
Total revenue from external customers	$	445	$	1,694	$	429	$	4		$	241		$	2,813
Intersegment revenue		5		10		252		139			(406	)		—
Total operating revenue		450		1,704		681		143			(165	)		2,813
Net income (loss) attributable to Dominion		116		159		130		(246	)		—			159
Three Months Ended June 30, 2013
Total revenue from external customers	$	432	$	1,898	$	354	$	17		$	279		$	2,980
Intersegment revenue		3		3		275		164			(445	)		—
Total operating revenue		435		1,901		629		181			(166	)		2,980
Loss from discontinued operations		—		—		—		(70	)		—			(70	)
Net income (loss) attributable to Dominion		112		185		124		(219	)		—			202
Six Months Ended June 30, 2014
Total revenue from external customers	$	945	$	3,951	$	791	$	7		$	749		$	6,443
Intersegment revenue		9		37		741		281			(1,068	)		—
Total operating revenue		954		3,988		1,532		288			(319	)		6,443
Net income (loss) attributable to Dominion		247		468		338		(515	)		—			538
Six Months Ended June 30, 2013
Total revenue from external customers	$	896	$	4,028	$	966	$	63		$	550		$	6,503
Intersegment revenue		5		44		539		307			(895	)		—
Total operating revenue		901		4,072		1,505		370			(345	)		6,503
Loss from discontinued operations		—		—		—		(69	)		—			(69	)
Net income (loss) attributable to Dominion		228		439		303		(273	)		—			697

(1) 2013 amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

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

Virginia Power 

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

In the six months ended June 30, 2014, Virginia Power reported an after-tax net expense of $181 million for specific items in the Corporate and Other segment, with $189 million of these net expenses attributable to its operating segments. In the six months ended June 30, 2013, Virginia Power reported an after-tax net expense of $5 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segments.

The net expense for specific items in 2014 primarily related to the impact of the following item:

• A $287 million ($191 million after-tax) charge associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, attributable to Dominion Generation.

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

	DVP		Dominion Generation		Corporate and Other			Consolidated Total
(millions)
Three Months Ended June 30, 2014
Operating revenue	$	448	$	1,281	$	—		$	1,729
Net income (loss)		117		133		(181	)		69
Three Months Ended June 30, 2013
Operating revenue	$	431	$	1,279	$	—		$	1,710
Net income (loss)		114		157		(6	)		265
Six Months Ended June 30, 2014
Operating revenue	$	950	$	2,762	$	—		$	3,712
Net income (loss)		251		322		(180	)		393
Six Months Ended June 30, 2013
Operating revenue	$	896	$	2,595	$	—		$	3,491
Net income (loss)		232		325		(5	)		552

Dominion Gas

The Corporate and Other Segment of Dominion Gasprimarily includes specific items attributable to Dominion Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance and the effect of certain items recorded at Dominion Gas as a result of Dominion’s basis in the net assets contributed.

In the six months ended June 30, 2014, Dominion Gas reported no amounts for specific items in the Corporate and Other segment. In the six months ended June 30, 2013, Dominion Gas reported an after-tax net expense of $41 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segment.

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

• A $55 million ($33 million after-tax) impairment charge related to certain natural gas infrastructure assets; and

• A $14 million ($8 million after-tax) charge primarily reflecting severance pay and other benefits related to workforce reductions.

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

	Dominion Energy		Corporate and Other			Consolidated Total
(millions)
Three Months Ended June 30, 2014
Operating revenue	$	428	$	—		$	428
Net income (loss)		96		(3	)		93
Three Months Ended June 30, 2013
Operating revenue	$	430	$	—		$	430
Net income (loss)		97		(44	)		53
Six Months Ended June 30, 2014
Operating revenue	$	997	$	—		$	997
Net income (loss)		262		(5	)		257
Six Months Ended June 30, 2013
Operating revenue	$	1,016	$	—		$	1,016
Net income (loss)		237		(46	)		191

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MD&A discusses Dominion’s and Virginia Power’s results of operations and general financial condition and Dominion Gas’ results of operations. MD&A should be read in conjunction with the Companies’ Consolidated Financial Statements. Dominion Gas meets the conditions to file under the reduced disclosure format, and therefore has omitted certain sections of MD&A.

Contents of MD&A

MD&A consists of the following information:

• Forward-Looking Statements

• Accounting Matters

• Dominion

• Results of Operations

• Segment Results of Operations

• Virginia Power

• Results of Operations

• Segment Results of Operations

• Dominion Gas

• Results of Operations

• Liquidity and Capital Resources

• Future Issues and Other Matters

Forward-Looking Statements

This report contains statements concerning the Companies’ 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.

The Companies make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:

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

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

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

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

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

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

• Unplanned outages at facilities in which the Companies have an ownership interest;

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

• Counterparty credit and performance risk;

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

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

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

• Fluctuations in interest rates;

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

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

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

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

• Impacts of acquisitions, divestitures, transfers of assets to joint ventures or an MLP, and retirements of assets based on asset portfolio reviews;

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

• The timing and execution of our MLP strategy;

• 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;

• Political and economic conditions, including inflation and deflation;

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

• Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, failure to maintain or replace customer contracts on favorable terms, 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;

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

• Changes in supplies of natural gas delivered to Dominion Gas’ systems;

• The impact of operational hazards, including adverse developments with respect to pipeline safety or integrity;

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

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

• Changes in operating, maintenance and construction costs;

• Timing and receipt of regulatory approvals necessary for planned construction or expansion projects and compliance with conditions associated with such regulatory approvals;

• 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;

• Adverse outcomes in litigation matters or regulatory proceedings; and

• The impact of operational hazards and other catastrophic events.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013, Exhibit 99.2 to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014, and in Part II. Item 1A. Risk Factors in this report.

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

Accounting Matters

Critical Accounting Policies and Estimates

As of June 30, 2014, there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013. The policies disclosed included the accounting for regulated operations, AROs, income taxes, derivative contracts and other instruments at fair value, goodwill and long-lived asset impairment testing, employee benefit plans and unbilled revenue.

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Dominion

Results of Operations

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

	2014		2013		$ Change
(millions, except EPS)
Second Quarter
Net income attributable to Dominion	$	159	$	202	$	(43	)
Diluted EPS		0.27		0.35		(0.08	)
Year-To-Date
Net income attributable to Dominion	$	538	$	697	$	(159	)
Diluted EPS		0.92		1.21		(0.29	)

Overview

Second Quarter 2014 vs. 2013

Net income attributable to Dominion decreased 21% primarily due to charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities. See Note 12 for further discussion of this matter. These decreases were partially offset by the absence of losses from discontinued operations related to Brayton Point and Kincaid, and the absence of impairment charges for certain natural gas infrastructure assets.

Year-To-Date 2014 vs. 2013

Net income attributable to Dominion decreased 23% primarily due to charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, and the repositioning of Dominion’s producer services business which was completed in the first quarter of 2014. These decreases were partially offset by the absence of losses from discontinued operations related to Brayton Point and Kincaid, the impact of higher margins from merchant generation operations, and more favorable weather on electric utility operations.

Analysis of Consolidated Operations

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

	Second Quarter								Year-To-Date
	2014		2013			$ Change			2014		2013			$ Change
(millions)
Operating revenue	$	2,813	$	2,980		$	(167	)	$	6,443	$	6,503		$	(60	)
Electric fuel and other energy-related purchases		633		875			(242	)		1,967		1,826			141
Purchased electric capacity		87		88			(1	)		175		176			(1	)
Purchased gas		324		297			27			864		764			100
Net revenue		1,769		1,720			49			3,437		3,737			(300	)
Other operations and maintenance		933		728			205			1,358		1,351			7
Depreciation, depletion and amortization		308		303			5			616		600			16
Other taxes		134		141			(7	)		301		308			(7	)
Other income		57		49			8			97		136			(39	)
Interest and related charges		227		203			24			464		431			33
Income tax expense		63		116			(53	)		249		404			(155	)
Loss from discontinued operations		—		(70	)		70			—		(69	)		69

An analysis of Dominion’s results of operations follows:

Second Quarter 2014 vs. 2013

Net revenue increased 3%, primarily reflecting:

• A $52 million increase primarily reflecting the absence of losses incurred in 2013 following the termination of natural gas trading and certain energy marketing activities related to the repositioning of Dominion’s producer services business which was completed in the first quarter of 2014; and

• A $30 million increase from electric utility operations, primarily reflecting:

• An increase in sales to retail customers ($9 million);

• An increase in ancillary revenues received from PJM ($8 million); and

• An increase from rate adjustment clauses ($7 million).

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These increases were partially offset by:

• A $15 million decrease from retail energy marketing operations, primarily due to the sale of the retail electric energy marketing business in March 2014;

• An $8 million decrease from regulated natural gas distribution operations, primarily due to a decrease in rider revenue related to low income assistance programs ($15 million), partially offset by an increase in AMR and PIR program revenues ($5 million); and

• A $7 million decrease from merchant generation operations, due to lower generation output primarily as a result of the May 2013 closure of Kewaunee ($20 million), partially offset by higher realized prices ($13 million).

Other operations and maintenance increased 28%, primarily reflecting:

• A $282 million charge associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities;

• The absence of a $29 million gain recorded in 2013 resulting from the sale of Illinois Gas Contracts following Dominion’s decision to redeploy its capital into other markets; and

• A $23 million increase in planned outage costs at certain non-nuclear utility generation facilities.

These increases were partially offset by:

• The absence of a $62 million charge primarily reflecting impairment charges recorded in 2013 for certain natural gas infrastructure assets;

• A $24 million decrease in utility nuclear refueling outage costs primarily due to the deferral of such costs beginning in the second quarter of 2014 pursuant to Virginia legislation enacted in April 2014;

• A $15 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income;

• A $12 million decrease related to the May 2013 closure of Kewaunee; and

• A $12 million decrease related to the sale of Dominion’s electric retail energy marketing business in March 2014.

Interest and related chargesincreased 12%, primarily due to higher long-term debt interest expense resulting from debt issuances in August and October 2013 and February and March 2014.

Income tax expensedecreased 46%, primarily reflecting lower pre-tax income in 2014.

Loss from discontinued operationsreflects the sale of Brayton Point and Kincaid in 2013.

Year-To-Date 2014 vs. 2013

Net revenue decreased 8%, primarily reflecting:

• A $270 million decrease primarily related to the repositioning of Dominion’s producer services business which was completed in the first quarter of 2014, reflecting the termination of natural gas trading and certain energy marketing activities;

• A $176 million decrease from retail energy marketing operations, primarily due to higher purchased power costs; and

• A $44 million decrease from regulated natural gas distribution operations, primarily due to a decrease in rider revenue related to low income assistance programs ($67 million), partially offset by an increase in AMR and PIR program revenues ($10 million) and an increase in sales to customers due to an increase in heating degree days ($7 million).

These decreases were partially offset by:

• A $152 million increase from electric utility operations, primarily reflecting:

• An increase in sales to retail customers, primarily due to an increase in heating degree days ($72 million);

• An increase from rate adjustment clauses ($51 million);

• An increase in ancillary revenues received from PJM ($29 million); and

• A $30 million increase from merchant generation operations, due to higher realized prices ($106 million), partially offset by lower generation output primarily as a result of the May 2013 closure of Kewaunee ($76 million).

Other operations and maintenance increased 1%, primarily reflecting:

• A $282 million charge associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities;

• A $42 million increase in planned outage costs primarily due to an increase in scheduled outage days at certain non-nuclear utility generation facilities;

• The absence of a $29 million gain recorded in 2013 resulting from the sale of Illinois Gas Contracts following Dominion’s decision to redeploy its capital into other markets; and

• A $28 million increase in salaries, wages and benefits.

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These increases were partially offset by:

• A gain on the sale of Dominion's electric retail energy marketing business ($100 million) net of a $31 million write-off of goodwill;

• A $67 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income;

• The absence of a $62 million charge primarily reflecting impairment charges recorded in 2013 for certain natural gas infrastructure assets;

• A $59 million decrease related to the May 2013 closure of Kewaunee;

• Increased gains due to the sale of assets to Blue Racer ($34 million);

• A $26 million decrease in utility nuclear refueling outage costs primarily due to the deferral of such costs beginning in the second quarter of 2014 pursuant to Virginia legislation enacted in April 2014; and

• A $20 million decrease in storm damage and service restoration costs.

Other incomedecreased 29%, primarily due to lower realized gains (net of investment income) on nuclear decommissioning trust funds ($26 million), a decrease in the equity component of AFUDC ($23 million) and an increase in donations expense ($9 million), partially offset by higher equity earnings primarily from Blue Racer ($18 million).

Income tax expensedecreased 38%, primarily reflecting lower pre-tax income in 2014.

Loss from discontinued operationsreflects the sale of Brayton Point and Kincaid in 2013.

Segment Results of Operations

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

	Net Income attributable to Dominion									Diluted EPS
Second Quarter	2014			2013			$ Change			2014			2013			$ Change
(millions, except EPS)
DVP(1)	$	116		$	112		$	4		$	0.20		$	0.20		$	—
Dominion Generation(1)		159			185			(26	)		0.27			0.32			(0.05	)
Dominion Energy		130			124			6			0.22			0.21			0.01
Primary operating segments		405			421			(16	)		0.69			0.73			(0.04	)
Corporate and Other		(246	)		(219	)		(27	)		(0.42	)		(0.38	)		(0.04	)
Consolidated	$	159		$	202		$	(43	)	$	0.27		$	0.35		$	(0.08	)
Year-To-Date
DVP(1)	$	247		$	228		$	19		$	0.42		$	0.39		$	0.03
Dominion Generation(1)		468			439			29			0.80			0.76			0.04
Dominion Energy		338			303			35			0.58			0.53			0.05
Primary operating segments		1,053			970			83			1.80			1.68			0.12
Corporate and Other		(515	)		(273	)		(242	)		(0.88	)		(0.47	)		(0.41	)
Consolidated	$	538		$	697		$	(159	)	$	0.92		$	1.21		$	(0.29	)

(1) 2013 amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Generation segment.

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DVP

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

	Second Quarter							Year-To-Date
	2014		2013		% Change			2014		2013		% Change
Electricity delivered (million MWh)		19.3		19.2		1	%		41.7		40.3		3	%
Degree days (electric distribution service area):
Cooling		529		539		(2	)		529		539		(2	)
Heating		252		303		(17	)		2,546		2,364		8
Average electric distribution customer accounts (thousands)(1)		2,495		2,472		1			2,494		2,470		1

(1) Period average.

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

	Second Quarter 2014 vs. 2013 Increase (Decrease)						Year-To-Date 2014 vs. 2013 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	2		$	—		$	15		$	0.03
Other		—			—			(4	)		(0.01	)
FERC transmission equity return		7			0.01			9			0.02
Storm damage and service restoration		7			0.01			12			0.03
Other		(12	)		(0.02	)		(13	)		(0.03	)
Share dilution		—			—			—			(0.01	)
Change in net income contribution	$	4		$	—		$	19		$	0.03

Dominion Generation

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

	Second Quarter							Year-To-Date
	2014		2013		% Change			2014			2013		% Change
Electricity supplied (million MWh):
Utility		19.4		19.3		1	%		41.9			40.5		3	%
Merchant(1)		5.8		5.8		—			12.2			12.7		(4	)
Degree days (electric utility service area):
Cooling		529		539		(2	)		529			539		(2	)
Heating		252		303		(17	)		2,546			2,364		8
Average retail energy marketing customer accounts (thousands)(2)		1,245		2,109		(41	)		1,340	(3)		2,117		(37	)

(1) Excludes 2.0 million and 6.0 million MWh for the three and six months ended June 30, 2013, respectively, related to Kewaunee, Brayton Point, Kincaid and Dominion’s 50% interest in Elwood.

(2) Period average.

(3) Excludes 511 thousand average retail electric energy marketing customer accounts due to the sale of this business in March 2014.

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

	Second Quarter 2014 vs. 2013 Increase (Decrease)						Year-To-Date 2014 vs. 2013 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Merchant generation margin	$	9		$	0.01		$	60		$	0.12
Regulated electric sales:
Weather		3			0.01			29			0.05
Other		(2	)		—			(8	)		(0.01	)
PJM ancillary services		5			0.01			26			0.04
Rate adjustment clause equity return		(17	)		(0.03	)		(19	)		(0.03	)
Retail energy marketing operations(1)		(18	)		(0.04	)		(18	)		(0.04	)
Salaries and benefits		(6	)		(0.01	)		(17	)		(0.03	)
Outage costs		2			—			(9	)		(0.02	)
Other		(2	)		—			(15	)		(0.03	)
Share dilution		—			—			—			(0.01	)
Change in net income contribution	$	(26	)	$	(0.05	)	$	29		$	0.04

(1) Excludes earnings from Retail electric energy marketing which was sold in March 2014.

Dominion Energy

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

	Second Quarter							Year-To-Date
	2014		2013		% Change			2014		2013		% Change
Gas distribution throughput (bcf):
Sales		4		4		—	%		21		18		17	%
Transportation		58		52		12			186		162		15
Heating degree days (gas distribution service area)		603		641		(6	)		4,116		3,664		12
Average gas distribution customer accounts (thousands)(1):
Sales		239		240		—			243		245		(1	)
Transportation		1,059		1,058		—			1,058		1,056		—

(1) Period average.

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

	Second Quarter 2014 vs. 2013 Increase (Decrease)						Year-To-Date 2014 vs. 2013 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Blue Racer	$	10		$	0.02		$	32	(1)	$	0.05
Gas distribution margin:
Weather		—			—			4			0.01
Other		3			0.01			10			0.02
Other		(7	)		(0.02	)		(11	)		(0.03	)
Change in net income contribution	$	6		$	0.01		$	35		$	0.05

(1) Includes a $21 million increase in gains from the sale of assets.

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Corporate and Other

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

	Second Quarter									Year-To-Date
	2014			2013			$ Change			2014			2013			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	(185	)	$	(148	)	$	(37	)	$	(402	)	$	(131	)	$	(271	)
Specific items attributable to corporate operations		(17	)		(5	)		(12	)		(28	)		(3	)		(25	)
Total specific items		(202	)		(153	)		(49	)		(430	)		(134	)		(296	)
Other corporate operations		(44	)		(66	)		22			(85	)		(139	)		54
Total net expense	$	(246	)	$	(219	)	$	(27	)	$	(515	)	$	(273	)	$	(242	)
EPS impact	$	(0.42	)	$	(0.38	)	$	(0.04	)	$	(0.88	)	$	(0.47	)	$	(0.41	)

Total Specific Items

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

Other Corporate Operations

Second Quarter 2014 vs. 2013

Net expenses decreased primarily reflecting increased investment tax credits in Dominion's 2014 estimated annual effective rate for income taxes.

Year-To-Date 2014 vs. 2013

Net expenses decreased primarily reflecting increased investment tax credits in Dominion's 2014 estimated annual effective rate for income taxes.

Virginia Power

Results of Operations

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

	Second Quarter							Year-To-Date
	2014		2013		$ Change			2014		2013		$ Change
(millions)
Net income	$	69	$	265	$	(196	)	$	393	$	552	$	(159	)

Overview

Second Quarter 2014 vs. 2013

Net income decreased by 74% primarily due to charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities. See Note 12 for further discussion of this matter.

Year-To-Date 2014 vs. 2013

Net income decreased by 29% primarily due to charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, partially offset by the impact of more favorable weather.

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Analysis of Consolidated Operations

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

	Second Quarter							Year-To-Date
	2014		2013		$ Change			2014		2013		$ Change
(millions)
Operating revenue	$	1,729	$	1,710	$	19		$	3,712	$	3,491	$	221
Electric fuel and other energy-related purchases		518		528		(10	)		1,168		1,098		70
Purchased electric capacity		87		88		(1	)		175		176		(1	)
Net revenue		1,124		1,094		30			2,369		2,217		152
Other operations and maintenance		633		355		278			974		674		300
Depreciation and amortization		217		211		6			435		418		17
Other taxes		69		65		4			142		132		10
Other income		21		27		(6	)		36		52		(16	)
Interest and related charges		103		84		19			210		177		33
Income tax expense		54		141		(87	)		251		316		(65	)

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

Second Quarter 2014 vs. 2013

Net revenue increased 3%, primarily reflecting:

• An increase in sales to retail customers ($9 million);

• An increase in ancillary revenues received from PJM ($8 million); and

• An increase from rate adjustment clauses ($7 million).

Other operations and maintenance increased 78%, primarily reflecting:

• A $282 million charge associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities; and

• A $24 million increase in planned outage costs at certain non-nuclear generation facilities; partially offset by

• A $24 million decrease in utility nuclear refueling outage costs primarily due to the deferral of such costs beginning in the second quarter of 2014 pursuant to Virginia legislation enacted in April 2014; and

• An $11 million decrease in storm damage and service restoration costs.

Interest and related chargesincreased 23%, primarily due to higher long-term debt interest expense resulting from debt issuances in August 2013 and February 2014 ($14 million) and a decrease in the debt component of AFUDC ($6 million).

Income tax expensedecreased 62%, primarily reflecting lower pre-tax income in 2014.

Year-To-Date 2014 vs. 2013

Net revenue increased 7%, primarily reflecting:

• An increase in sales to retail customers, primarily due to an increase in heating degree days ($72 million);

• An increase from rate adjustment clauses ($51 million); and

• An increase in ancillary revenues received from PJM ($29 million).

Other operations and maintenance increased 45%, primarily reflecting:

• A $282 million charge associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities;

• A $42 million increase in planned outage costs primarily due to an increase in scheduled outage days at certain non-nuclear generation facilities; and

• A $19 million increase in salaries, wages and benefits.

These increases were partially offset by:

• A $26 million decrease in utility nuclear refueling outage costs primarily due to the deferral of such costs beginning in the second quarter of 2014 pursuant to Virginia legislation enacted in April 2014; and

• A $20 million decrease in storm damage and service restoration costs.

Other income decreased 31%, primarily due to a decrease in the equity component of AFUDC.

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Interest and related chargesincreased 19%, primarily due to higher long-term debt interest expense resulting from debt issuances in August 2013 and February 2014 ($25 million) and a decrease in the debt component of AFUDC ($8 million).

Income tax expensedecreased 21%, primarily reflecting lower pre-tax income in 2014.

Segment Results of Operations

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

	Second Quarter									Year-To-Date
	2014			2013			$ Change			2014			2013			$ Change
(millions)
DVP	$	117		$	114		$	3		$	251		$	232		$	19
Dominion Generation		133			157			(24	)		322			325			(3	)
Primary operating segments		250			271			(21	)		573			557			16
Corporate and Other		(181	)		(6	)		(175	)		(180	)		(5	)		(175	)
Consolidated	$	69		$	265		$	(196	)	$	393		$	552		$	(159	)

DVP

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

	Second Quarter							Year-To-Date
	2014		2013		% Change			2014		2013		% Change
Electricity delivered (million MWh)		19.3		19.2		1	%		41.7		40.3		3	%
Degree days (electric distribution service area):
Cooling		529		539		(2	)		529		539		(2	)
Heating		252		303		(17	)		2,546		2,364		8
Average electric distribution customer accounts (thousands)(1)		2,495		2,472		1			2,494		2,470		1

(1) Period average.

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

	Second Quarter 2014 vs. 2013 Increase (Decrease)			Year-To-Date 2014 vs.  2013 Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	2		$	15
Other		—			(4	)
FERC transmission equity return		7			9
Storm damage and service restoration		7			12
Other		(13	)		(13	)
Change in net income contribution	$	3		$	19

Dominion Generation

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

	Second Quarter							Year-To-Date
	2014		2013		% Change			2014		2013		% Change
Electricity supplied (million MWh):		19.4		19.3		1	%		41.9		40.5		3	%
Degree days (electric utility service area):
Cooling		529		539		(2	)		529		539		(2	)
Heating		252		303		(17	)		2,546		2,364		8

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

	Second Quarter 2014 vs. 2013 Increase (Decrease)			Year-To-Date 2014 vs. 2013 Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	3		$	29
Other		(2	)		(8	)
Rate adjustment clause equity return		(17	)		(19	)
PJM ancillary services		5			26
Salaries and benefits		(3	)		(8	)
Outage costs		—			(10	)
Other		(10	)		(13	)
Change in net income contribution	$	(24	)	$	(3	)

Corporate and Other

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

Dominion Gas

Results of Operations

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

	Second Quarter						Year-To-Date
	2014		2013		$ Change		2014		2013		$ Change
(millions)
Net income	$	93	$	53	$	40	$	257	$	191	$	66

Overview

Second Quarter 2014 vs. 2013

Net income increased by 75% primarily due to the absence of impairment charges for certain natural gas infrastructure assets.

Year-To-Date 2014 vs. 2013

Net income increased by 35% primarily due to the absence of impairment charges for certain natural gas infrastructure assets and increased gains due to the sale of pipeline systems.

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Analysis of Consolidated Operations

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

	Second Quarter							Year-To-Date
	2014		2013		$ Change			2014		2013		$ Change
(millions)
Operating revenue	$	428	$	430	$	(2	)	$	997	$	1,016	$	(19)
Purchased gas		76		63		13			213		177		36
Other energy-related purchases		5		18		(13	)		21		40		(19	)
Net revenue		347		349		(2	)		763		799		(36	)
Other operations and maintenance		109		178		(69	)		162		308		(146	)
Depreciation and amortization		49		50		(1	)		96		99		(3	)
Other taxes		35		33		2			86		80		6
Other income		5		3		2			13		14		(1	)
Interest and related charges		6		6		—			12		13		(1	)
Income tax expense		60		32		28			163		122		41

An analysis of Dominion Gas’ results of operations follows:

Second Quarter 2014 vs. 2013

Other operations and maintenance decreased 39%, primarily reflecting:

• The absence of impairment charges recorded in 2013 related to certain natural gas infrastructure assets ($55 million); and

• A $15 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income.

Income tax expenseincreased 88%, primarily reflecting higher pre-tax income in 2014.

Year-To-Date 2014 vs. 2013

Net revenue decreased 5%, primarily reflecting:

• A decrease in rider revenue primarily related to low income assistance programs ($67 million); and

• A decrease from NGL activities primarily due to lower sales volumes ($18 million).

These decreases were partially offset by:

• An increase in transportation and storage activities and other revenues ($30 million);

• An increase in AMR and PIR program revenues ($10 million); and

• An increase in sales to gas distribution customers primarily due to an increase in heating degree days ($4 million).

Other operations and maintenance decreased 47%, primarily reflecting:

• A $67 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income;

• The absence of impairment charges recorded in 2013 related to certain natural gas infrastructure assets ($55 million); and

• Increased gains due to the sale of pipeline systems ($34 million).

Income tax expenseincreased 34%, primarily reflecting higher pre-tax income in 2014.

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 June 30, 2014, Dominion had $1.3 billion of unused capacity under its credit facilities. At June 30, 2014, Virginia Power’s facility sub-limit was exceeded; however, Virginia Power retained ongoing access to its short-term demand note with Dominion and remained in compliance with its debt covenants. Effective July 10, 2014, Virginia Power increased its sub-limit under the $4 billion credit facility from $1.0 billion to $1.25 billion bringing its total sub-limit to $1.5 billion.

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The sale of the electric retail energy marketing business and completion of the producer services repositioning in 2014 are not expected to have a material negative impact on Dominion’s liquidity.

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

	2014			2013
(millions)
Cash and cash equivalents at January 1	$	316		$	248
Cash flows provided by (used in):
Operating activities		1,447			1,791
Investing activities		(2,186	)		(1,885	)
Financing activities		842			36
Net increase (decrease) in cash and cash equivalents		103			(58	)
Cash and cash equivalents at June 30	$	419		$	190

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

	2014			2013
(millions)
Cash and cash equivalents at January 1	$	16		$	28
Cash flows provided by (used in):
Operating activities		909			1,115
Investing activities		(1,539	)		(1,337	)
Financing activities		672			208
Net increase (decrease) in cash and cash equivalents		42			(14	)
Cash and cash equivalents at June 30	$	58		$	14

Operating Cash Flows

Net cash provided by Dominion’s operating activities decreased by $344 million, primarily due to lower deferred fuel cost recoveries in its Virginia jurisdiction, the repositioning of Dominion’s producer services business, and lower margins from nonregulated retail energy marketing operations. The decrease was partially offset by lower net margin collateral requirements, higher margins from merchant generation operations, and the impact of more favorable weather in 2014.

Net cash provided by Virginia Power's operating activities decreased by $206 million, primarily due to lower deferred fuel cost recoveries, partially offset by the impact of more favorable weather in 2014 and net changes in other working capital items.

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

Dominion’s and Virginia Power’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, which are discussed in Item 1A. Risk Factors in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013.

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 June 30, 2014 for these activities. Gross credit exposure for each counterparty is calculated prior to the application of collateral and represents outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

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	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade(1)	$	39	$	—	$	39
Non-investment grade(2)		2		—		2
No external ratings:
Internally rated—investment grade(3)		33		—		33
Internally rated—non-investment grade(4)		48		—		48
Total	$	122	$	—	$	122

(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 19% 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 22% of the total net credit exposure.

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

Investing Cash Flows

Net cash used in Dominion’s investing activities increased by $301 million, primarily due to higher capital expenditures partially offset by higher proceeds from sales of assets.

Net cash used in Virginia Power's investing activities increased by $202 million, primarily due to higher capital expenditures.

Financing Cash Flows and Liquidity

Dominion and Virginia Power rely on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by their operations. As discussed further inCredit Ratingsand Debt Covenants in MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013, the ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC and, in the case of Virginia Power, approval by the Virginia Commission.

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

In 2014, net cash provided by Dominion’s financing activities increased by $806 million primarily due to higher net debt issuances in 2014 as compared to 2013, mainly as a result of higher capital needs and lower cash flow from operations.

In 2014, net cash provided by Virginia Power's financing activities increased by $464 million, primarily due to higher net debt issuances, mainly as a result of higher capital needs and lower cash flow from operations, partially offset by the redemption of preferred stock in 2014.

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

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In theCredit Ratings section of MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013, there is a discussion on the use of capital markets by Dominion and Virginia Power as well as the impact of credit ratings on the accessibility and costs of using these markets. As of June 30, 2014, there have been no changes in Dominion's and Virginia Power’s credit ratings.

Debt Covenants

In theDebt Covenants section of MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013, there is a discussion on the various covenants present in the enabling agreements underlying Dominion’s and Virginia Power’s debt. As of June 30, 2014, there have been no material changes to debt covenants, nor any events of default under Dominion’s and Virginia Power’s debt covenants.

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In July 2014, Dominion amended the RCC of the June 2009 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock or other equity-like issuances from 180 days to 365 days.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of June 30, 2014, there have been no material changes outside the ordinary course of business to Dominion’s or Virginia Power’s contractual obligations nor any material changes to planned capital expenditures as disclosed in MD&A in Dominion’s and Virginia Power's Annual Report on Form 10-K for the year ended December 31, 2013.

Use of Off-Balance Sheet Arrangements

As of June 30, 2014, there have been no material changes in the off-balance sheet arrangements disclosed in MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013.

Future Issues and Other Matters

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by, and subsequent to, the dates of Dominion’s and Virginia Power’s Consolidated Financial Statements that may impact Dominion’s and Virginia Power’s future results of operations, financial condition and/or cash flows. This section should be read in conjunction withItem 1. Business andFuture Issues and Other Matters in MD&A in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 andFuture Issues and Other Mattersin MD&A in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014.

Environmental Matters

Dominion and Virginia Power are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. See Note 22 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 and Note 15 in this report for additional information on various environmental matters.

Climate Change Legislation and Regulation

In April 2012, the EPA published proposed NSPS for GHG emissions for new electric generating units. This proposed rule set national emission standards for new coal, oil, integrated gasification, and combined cycle units larger than 25 MW. 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 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.

In June 2014, the EPA issued proposed guidelines called the “Clean Power Plan” for states to follow in developing plans to reduce CO₂ emissions from existing fossil fuel-fired electric generating units. The guidelines use a set of measures for reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units, expanding renewable resources and increasing customer energy efficiency. The proposal would require states to meet state-by-state emission rate or intensity-based CO₂ binding goals or limits. The EPA is expected to finalize the guidelines by June 2015. States will then be required to submit plans to the EPA by June 30, 2016 identifying how they will comply with the rule, with possible one- or two-year extensions. Until the state plans are developed and the EPA approves the plans, Dominion and Virginia Power cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.

In June 2014, the EPA published proposed performance standards to address CO₂ emissions from modified and reconstructed electric generating units. The proposed standards would only apply to coal- and natural-gas fired boilers and natural gas-fired combined cycle units, constructed for the purpose of supplying more than one-third of their potential output to the grid and which are designed to sell more than 219,000 MWhs in a year (roughly equivalent to 25 MW), that meet certain, specific conditions described in the CAA for being “modified” or “reconstructed.” Modifications undertaken for the primary purpose of installing pollution control technology will not be subject to the proposed standards. Dominion and Virginia Power cannot predict the direct or indirect financial impact of this proposed rule on operations at this time.

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In March 2014, a national Strategy to Reduce Methane Emissions was published as part of the Climate Action Plan. The plan outlines a strategy to further reduce both domestic and international methane emissions from a number of key sources, including the oil and natural gas industry, and outlines the President’s efforts to improve measurement of these emissions. In April 2014, the EPA published five white papers on methane emissions and potential mitigation options related to the oil and gas industry. The EPA is expected to make a decision on whether to regulate methane emissions from the oil and natural gas industry in late 2014. The EPA expects to complete any additional regulations deemed to be necessary by the end of 2016. Dominion currently cannot predict the direct or indirect financial impact on operations from these GHG initiatives, but believes the expenditures to comply with any new requirements could be material.

Legal Matters

See Item 3. Legal Proceedings in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013, and Notes 12 and 15 to the Consolidated Financial Statements and Part II, Item 1. Legal Proceedings in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 and in this report for additional information on various legal matters.

Regulatory Matters

See Note 13 to the Consolidated Financial Statements in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 and Note 12 in Dominion’s and Virginia Power’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 and in this report for additional information on various regulatory matters.

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.

In April 2013, Cove Point filed with FERC for permission to build liquefaction and other facilities related to the export of natural gas. In May 2014, the FERC staff issued its environmental assessment for the liquefaction project. Based on the analysis in the environmental assessment, the FERC staff determined that with the implementation of appropriate mitigation measures, the liquefaction project can be built and operated safely with no significant impact to the environment. The mitigation measures proposed in the environmental assessment are not final. Until the FERC approves the liquefaction project, the mitigation measures and associated conditions are nonbinding and are subject to change, and the estimated costs and impact of implementing such measures cannot yet be determined. The application is currently pending before the FERC.

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 May 2014, the Maryland Commission granted a CPCN authorizing the construction of such generating station. The CPCN is contingent upon Cove Point receiving FERC approval for the liquefaction project and will obligate Cove Point to make payments over time totaling approximately $48 million to the Maryland Strategic Energy Investments Fund and Maryland low income energy assistance programs. In June 2014, a party filed a notice of petition for judicial review of the CPCN with the Circuit Court for Baltimore City in Maryland. This matter is currently pending.

Dominion is party to an agreement with the Sierra Club restricting activities on portions of the Cove Point property. In February 2014, the Maryland Court of Special Appeals affirmed a circuit court’s prior ruling that Cove Point may locate, construct and operate a liquefaction plant at the Cove Point LNG Facility and export LNG from the Cove Point LNG Facility. In April 2014, the Sierra Club petitioned the Maryland Court of Appeals, Maryland's highest court, to review the rulings of the circuit court and the Maryland Court of Special Appeals. In June 2014, the Maryland Court of Appeals declined the appeal petition.

Western Access II Project

During the second quarter of 2014, East Ohio executed a long-term precedent agreement with a customer for 350,000 Dths per day of service to new interconnects with interstate pipelines. This second phase of the Western Access Project will expand the number of interstate pipelines to which East Ohio will deliver processed gas to four. The project is expected to be completed in the fourth quarter of 2015 and cost approximately $130 million.

Monroe-to-Cornwell Project

During the second quarter of 2014, DTI executed a binding precedent agreement with a customer for the Monroe-to-Cornwell Project. The project is expected to cost approximately $70 million and provide 205,000 Dths per day of firm transportation service from Monroe County, Ohio to an interconnect near Cornwell, West Virginia. 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.

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ITEM 3.

QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

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

Market Risk Sensitive Instruments and Risk Management

The Companies’ 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 and Dominion Gas’ gas procurement and marketing 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 and future issuances of debt. In addition, the Companies 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 commodity 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 and Dominion Gas primarily holds commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of natural gas and other energy-related products.

The repositioning of Dominion's producer services business was completed in the first quarter of 2014. This, combined with Dominion's sale of its electric retail energy marketing business, has reduced 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 a decrease in fair value of approximately $152 million and $171 million as of June 30, 2014 and December 31, 2013, 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 June 30, 2014 or December 31, 2013.

A hypothetical 10% unfavorable change in commodity prices of Dominion Gas' non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $7 million and $14 million as of June 30, 2014 and December 31, 2013, respectively. The decline in sensitivity is largely due to decreased commodity derivative activity.

The impact of a change in energy commodity prices on the Companies' 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

The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt and interest rate swaps designated under fair value hedging and outstanding for the Companies, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at June 30, 2014 or December 31, 2013.

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The Companies may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges.

As of June 30, 2014, Dominion, Virginia Power and Dominion Gas had $2.9 billion, $550 million and $800 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 $51 million, $9 million and $25 million, respectively, in the fair value of Dominion's, Virginia Power's and Dominion Gas' interest rate derivatives at June 30, 2014. As of December 31, 2013, Dominion, Virginia Power and Dominion Gas had $1.1 billion, $600 million and $450 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, $13 million and $8 million, respectively, in the fair value of Dominion's, Virginia Power's and Dominion Gas' interest rate derivatives at December 31, 2013.

The impact of a change in interest rates on the Companies' 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 $71 million, $93 million and $163 million for the six months ended June 30, 2014 and 2013 and for the year ended December 31, 2013, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $127 million, $130 million and $417 million for the six months ended June 30, 2014 and 2013 and for the year ended December 31, 2013, respectively.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $32 million, $28 million and $52 million for the six months ended June 30, 2014 and 2013 and for the year ended December 31, 2013, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $61 million, $69 million and $193 million for the six months ended June 30, 2014 and 2013 and for the year ended December 31, 2013, respectively.

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

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ITEM 4. CONTROLS AND PROCEDURES

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

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

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

• Notes 13 and 22 to the Consolidated Financial Statements andFuture Issues and Other Matters in MD&A in Dominion's and Virginia Power's Annual Report on Form 10-K for the year ended December 31, 2013.

• Notes 12 and 15 to the Consolidated Financial Statements in Dominion's and Virginia Power's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014.

• Notes 12 and 18 to the Audited Consolidated Financial Statements in Exhibit 99.11(b) to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014.

• Notes 11 and 13 to the Unaudited Consolidated Financial Statements in Exhibit 99.11(c) to Dominion Gas’ Current Report on Form 8-K dated June 26, 2014.

• Notes 12 and 15 to the Consolidated Financial Statements in this report.

ITEM 1A. RISK FACTORS

The Companies businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond the Companies’ control. A number of these risk factors have been identified in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 and in Exhibit 99.2 to Dominion Gas' Current Report on Form 8-K dated June 26, 2014, which should be taken into consideration when reviewing the information contained in this report. Other than the risk factor discussed below, there have been no material changes with regard to the risk factors previously disclosed in Dominion’s and Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2013 and in Exhibit 99.2 to Dominion Gas' Current Report on Form 8-K dated June 26, 2014. 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, seeForward-Looking Statements in MD&A.

The development, construction and operation of the Cove Point liquefaction project would involve significant risks.As described in greater detail inFuture Issues and Other Matters in Dominion’s Annual Report on Form 10-K for the year ended December 31, 2013, 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 approval. Additionally, Dominion must comply with conditions imposed by regulatory 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 in the past and could be the subject of litigation in the future. A delay in receipt of project approval, failure to comply with regulatory approval conditions or an adverse ruling in any future litigation 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.

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.

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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 inFuture Issues and Other Mattersin Dominion’s Annual Report on Form 10-K for the year ended December 31, 2013, which could have a negative impact on its results of operations.

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

Dominion

ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares (or Units) Purchased(1)		Average Price Paid per Share (or Unit)(2)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(3)
4/1/14-4/30/14		1,574	$	70.40		—	19,629,059 shares/ $1.18 billion
5/1/14-5/31/14		—		—		—	19,629,059 shares/ $1.18 billion
6/1/14-6/30/14		—		—		—	19,629,059 shares/ $1.18 billion
Total		1,574	$	70.40		—	19,629,059 shares/ $1.18 billion

(1) In April 2014, 1,574 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 BOD in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion BOD was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion.

ITEM 6. EXHIBITS

Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas
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 April 28, 2014 (Exhibit 3.1.b, Form 10-Q filed April 30, 2014, File No. 1-2255).		X
3.1.c	Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).			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
3.2.c	Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066).			X
4	Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC 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	X

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4.1	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); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489).	X
4.2	2014 Series A Purchase Contract and Pledge Agreement, dated as of July 1, 2014, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.5, Form 8-K filed July 1, 2014, File No. 1-8489).	X
4.3	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), as amended by Amendment No. 1 to Replacement Capital Covenant dated July 18, 2014 (filed herewith).	X
10.1*	Dominion Resources, Inc. 2014 Incentive Compensation Plan, effective May 7, 2014 (Exhibit 10.1, Form 8-K filed May 7, 2014, File No. 1-8489).	X	X	X
10.2	$4,000,000,000 Five-Year Amended and Restated Revolving Credit Agreement, dated May 19, 2014, among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, The Royal Bank of Scotland plc, Bank of America, N.A., Barclays Bank PLC and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein (Exhibit 10.1, Form 8-K filed May 19, 2014, File No. 1-8489 and File No. 1-2255).	X	X	X
10.3	$500,000,000 Five-Year Amended and Restated Revolving Credit Agreement, dated May 30, 2014, among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, Keybank National Association, as Administrative Agent, U.S. Bank National Association, as Syndication Agent, and other lenders named therein (Exhibit 10.1, Form 8-K filed June 2, 2014, File No. 1-8489 and File No. 1-2255).	X	X	X
10.4*	Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated May 7, 2014 (filed herewith).	X	X	X
12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X
12.2.a	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).		X
12.2.b	Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).		X
12.3	Ratio of earnings to fixed charges for Dominion Gas Holdings, LLC (filed herewith).			X
31.a	Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.b	Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.c	Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
31.d	Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X

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31.e	Certification by Chief Executive Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).			X
31.f	Certification by Chief Financial Officer of Dominion Gas Holdings, LLC 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
32.c	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).			X
99	Condensed consolidated earnings statements (filed herewith).	X	X
101	The following financial statements from Dominion Resources, Inc.’s, Virginia Electric and Power Company’s and Dominion Gas Holdings, LLC’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, filed on July 30, 2014, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Comprehensive Income (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.	X	X	X

* Indicates management contract or compensatory plan or arrangement.

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SIGNATURE

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

	DOMINION RESOURCES, INC. Registrant
July 30, 2014	/s/    Michele L. Cardiff
	Michele L. Cardiff
	Vice President, Controller and Chief Accounting Officer
	VIRGINIA ELECTRIC AND POWER COMPANY Registrant
July 30, 2014	/s/    Michele L. Cardiff
	Michele L. Cardiff
	Vice President, Controller and Chief Accounting Officer
July 30, 2014	DOMINION GAS HOLDINGS, LLC Registrant
	/s/    Michele L. Cardiff
	Michele L. Cardiff
	Vice President, Controller and
	Chief Accounting Officer

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EXHIBIT INDEX

Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas
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 April 28, 2014 (Exhibit 3.1.b, Form 10-Q filed April 30, 2014, File No. 1-2255).		X
3.1.c	Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).			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
3.2.c	Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066).			X
4	Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC 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	X
4.1	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); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489).	X
4.2	2014 Series A Purchase Contract and Pledge Agreement, dated as of July 1, 2014, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.5, Form 8-K filed July 1, 2014, File No. 1-8489).	X
4.3	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), as amended by Amendment No. 1 to Replacement Capital Covenant dated July 18, 2014 (filed herewith).	X
10.1*	Dominion Resources, Inc. 2014 Incentive Compensation Plan, effective May 7, 2014 (Exhibit 10.1, Form 8-K filed May 7, 2014, File No. 1-8489).	X	X	X
10.2	$4,000,000,000 Five-Year Amended and Restated Revolving Credit Agreement, dated May 19, 2014, among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, The Royal Bank of Scotland plc, Bank of America, N.A., Barclays Bank PLC and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein (Exhibit 10.1, Form 8-K filed May 19, 2014, File No. 1-8489 and File No. 1-2255).	X	X	X

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10.3	$500,000,000 Five-Year Amended and Restated Revolving Credit Agreement, dated May 30, 2014, among Dominion Resources, Inc., Virginia Electric and Power Company, Dominion Gas Holdings, LLC, Keybank National Association, as Administrative Agent, U.S. Bank National Association, as Syndication Agent, and other lenders named therein (Exhibit 10.1, Form 8-K filed June 2, 2014, File No. 1-8489 and File No. 1-2255).	X	X	X
10.4*	Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated May 7, 2014 (filed herewith).	X	X	X
12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X
12.2.a	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).		X
12.2.b	Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).		X
12.3	Ratio of earnings to fixed charges for Dominion Gas Holdings, LLC (filed herewith).			X
31.a	Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.b	Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.c	Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
31.d	Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
31.e	Certification by Chief Executive Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).			X
31.f	Certification by Chief Financial Officer of Dominion Gas Holdings, LLC 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
32.c	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).			X
99	Condensed consolidated earnings statements (filed herewith).	X	X
101	The following financial statements from Dominion Resources, Inc.’s, Virginia Electric and Power Company’s and Dominion Gas Holdings, LLC’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, filed on July 30, 2014, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Comprehensive Income (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.	X	X	X

* Indicates management contract or compensatory plan or arrangement.

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