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, 2015

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
000-55337	VIRGINIA ELECTRIC AND POWER COMPANY	54-0418825
000-55338	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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Dominion Resources, Inc.    Yes  x    No  ¨	Virginia Electric and Power Company    Yes  x    No  ¨
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, 2015, the latest practicable date for determination, Dominion Resources, Inc. had 594,321,909 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.

VIRGINIA ELECTRIC AND POWER COMPANY AND DOMINION GAS HOLDINGS, LLC MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND ARE 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		78
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		90
Item 4.	Controls and Procedures		92
	PART II. Other Information
Item 1.	Legal Proceedings		93
Item 1A.	Risk Factors		93
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		93
Item 6.	Exhibits		94

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
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
ATEX line	Appalachia to Texas Express ethane line
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion, Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc.
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 between Dominion and Caiman
BOD	Board of Directors
BP	BP Wind Energy North America Inc.
BREDL	Blue Ridge Environmental Defense League
Bremo	Bremo power station
CAA	Clean Air Act
Caiman	Caiman Energy II, LLC
CAIR	Clean Air Interstate Rule
CAISO	California independent system operator
CCR	Coal combustion residual
CEO	Chief Executive Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
CFO	Chief Financial Officer
Chesapeake	Chesapeake power station
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
Cove Point	Dominion Cove Point LNG, LP
CPCN	Certificate of Public Convenience and Necessity
CSAPR	Cross State Air Pollution Rule
CWA	Clean Water Act
D.C.	District of Columbia
DCGT	Dominion Carolina Gas Transmission, LLC (successor by statutory conversion to and formerly known as Carolina Gas Transmission Corporation)
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 Iroquois	Dominion Iroquois, Inc., which holds a 24.72% general partnership interest in Iroquois
Dominion Midstream	The legal entity, Dominion Midstream Partners, LP, one or more of its consolidated subsidiaries, Cove Point Holdings and DCGT (beginning April 1, 2015), or the entirety of Dominion Midstream Partners, LP, and its consolidated subsidiaries

3

Abbreviation or Acronym	Definition
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
DRS	Dominion Resources Services, Inc.
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
Enterprise	Enterprise Product Partners, L.P.
EPA	Environmental Protection Agency
EPC	Engineering, procurement and construction
EPS	Earnings per share
FERC	Federal Energy Regulatory Commission
Four Brothers	Four Brothers Solar, LLC, a limited liability company owned by Dominion and Four Brothers Holdings, LLC, a wholly-owned subsidiary of SunEdison
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
Greensville County	An approximately 1,588 MW proposed natural gas-fired combined-cycle power station in Greensville County, Virginia
Heating degree days	Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
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
Kewaunee	Kewaunee nuclear power station
kV	Kilovolt
LNG	Liquefied natural gas
MATS	Utility Mercury and Air Toxics Standard Rule
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.
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
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

4

Abbreviation or Acronym	Definition
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 deployed by East Ohio
PJM	PJM Interconnection, L.L.C.
Possum Point	Possum Point power station
ppb	Parts-per-billion
PSD	Prevention of Significant Deterioration
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 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 U	A rate adjustment clause associated with the recovery of costs of new underground distribution facilities
Rider W	A rate adjustment clause associated with the recovery of costs related to Warren County
ROE	Return on equity
RTO	Regional transmission organization
SEC	Securities and Exchange Commission
SELC	Southern Environmental Law Center
Shell	Shell WindEnergy, Inc.
SO2	Sulfur dioxide
Standard & Poor’s	Standard & Poor’s Ratings Services, a division of McGraw Hill Financial, Inc.
SunEdison	The legal entity, SunEdison, Inc., one or more of its consolidated subsidiaries (including Four Brothers Holdings, LLC) or operating segments, or the entirety of SunEdison, Inc. and its consolidated subsidiaries
U.S.	United States of America
UAO	Unilateral Administrative Order
UEX Rider	Uncollectible Expense Rider deployed by East Ohio
VDEQ	Virginia Department of Environmental Quality
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 1,342 MW combined-cycle, natural gas-fired power station in Warren County, Virginia
WVDEP	West Virginia Department of Environmental Protection
Yorktown	Yorktown power station

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,
	2015		2014		2015		2014
(millions, except per share amounts)
Operating Revenue	$	2,747	$	2,813	$	6,156	$	6,443
Operating Expenses
Electric fuel and other energy-related purchases		591		633		1,544		1,967
Purchased electric capacity		90		87		184		175
Purchased gas		111		324		361		864
Other operations and maintenance		709		933		1,311		1,358
Depreciation, depletion and amortization		339		308		682		616
Other taxes		134		134		299		301
Total operating expenses		1,974		2,419		4,381		5,281
Income from operations		773		394		1,775		1,162
Other income		56		57		116		97
Interest and related charges		221		227		444		464
Income from operations including noncontrolling interests before income tax expense		608		224		1,447		795
Income tax expense		190		63		489		249
Net Income Including Noncontrolling Interests		418		161		958		546
Noncontrolling Interests		5		2		9		8
Net Income Attributable to Dominion	$	413	$	159	$	949	$	538
Earnings Per Common Share
Net income attributable to Dominion - Basic	$	0.70	$	0.27	$	1.61	$	0.92
Net income attributable to Dominion - Diluted		0.70		0.27		1.60		0.92
Dividends declared per common share	$	0.6475	$	0.6000	$	1.2950	$	1.2000

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

6

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
(millions)
Net income including noncontrolling interests	$	418		$	161		$	958		$	546
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		92			(59	)		34			(209	)
Changes in unrealized net gains (losses) on investment securities(2)		(11	)		49			4			78
Changes in unrecognized pension and other postretirement benefit costs(3)		3			4			3			—
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities(4)		(61	)		(16	)		(2	)		144
Net realized gains on investment securities(5)		(12	)		(7	)		(33	)		(18	)
Net pension and other postretirement benefit costs(6)		12			9			25			17
Changes in other comprehensive income (loss) from equity method investees(7)		—			2			(1	)		(5	)
Total other comprehensive income (loss)		23			(18	)		30			7
Comprehensive income including noncontrolling interests		441			143			988			553
Comprehensive income attributable to noncontrolling interests		5			2			9			8
Comprehensive income attributable to Dominion	$	436		$	141		$	979		$	545

(1) Net of $(59) million and $47 million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $(19) million and $126 million for the six months ended June 30, 2015 and 2014, respectively.

(2) Net of $6 million and $(27) million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $(5) million and $(28) million for the six months ended June 30, 2015 and 2014, respectively.

(3) Net of $3 million and $4 million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $3 million and $— million for the six months ended June 30, 2015 and 2014, respectively.

(4) Net of $41 million and $6 million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $2 million and $(94) million for the six months ended June 30, 2015 and 2014, respectively.

(5) Net of $8 million and $4 million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $20 million and $11 million for the six months ended June 30, 2015 and 2014, respectively.

(6) Net of $(9) million and $(6) million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $(18) million and $(12) million for the six months ended June 30, 2015 and 2014, respectively.

(7) Net of $1 million and $3 million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $1 million and $3 million for the six months ended June 30, 2015 and 2014, respectively.

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

7

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2015			December 31, 2014(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	271		$	318
Customer receivables (less allowance for doubtful accounts of $37 and $34)		1,334			1,514
Other receivables (less allowance for doubtful accounts of $2 and $3)		106			119
Inventories		1,260			1,410
Prepayments		120			167
Deferred income taxes		517			800
Other		844			1,287
Total current assets		4,452			5,615
Investments
Nuclear decommissioning trust funds		4,208			4,196
Investment in equity method affiliates		1,103			1,081
Other		274			284
Total investments		5,585			5,561
Property, Plant and Equipment
Property, plant and equipment		54,448			51,406
Accumulated depreciation, depletion and amortization		(15,780	)		(15,136	)
Total property, plant and equipment, net		38,668			36,270
Deferred Charges and Other Assets
Goodwill		3,294			3,044
Pension and other postretirement benefit assets		1,002			956
Regulatory assets		1,625			1,642
Other		1,316			1,239
Total deferred charges and other assets		7,237			6,881
Total assets	$	55,942		$	54,327

(1) Dominion’s Consolidated Balance Sheet at December 31, 2014 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.

8

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	June 30, 2015			December 31, 2014(1)
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	1,310		$	1,375
Short-term debt		2,622			2,775
Accounts payable		842			952
Accrued interest, payroll and taxes		527			566
Other(2)		1,435			1,530
Total current liabilities		6,736			7,198
Long-Term Debt
Long-term debt		19,597			18,348
Junior subordinated notes		1,373			1,374
Remarketable subordinated notes		2,084			2,083
Total long-term debt		23,054			21,805
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		7,573			7,444
Asset retirement obligations		1,812			1,633
Regulatory liabilities		2,130			1,991
Other		1,782			2,299
Total deferred credits and other liabilities		13,297			13,367
Total liabilities		43,087			42,370
Commitments and Contingencies (see Note 16)
Equity
Common stock – no par(3)		6,530			5,876
Retained earnings		6,278			6,095
Accumulated other comprehensive loss		(386	)		(416	)
Total common shareholders’ equity		12,422			11,555
Noncontrolling interests		433			402
Total equity		12,855			11,957
Total liabilities and equity	$	55,942		$	54,327

(1) Dominion’s Consolidated Balance Sheet at December 31, 2014 has been derived from the audited Consolidated Financial Statements at that date.

(2) See Note 3 for amounts attributable to related parties.

(3) 1 billion shares authorized; 594 million shares and 585 million shares outstanding at June 30, 2015 and December 31, 2014, respectively.

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

9

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,	2015			2014
(millions)
Operating Activities
Net income including noncontrolling interests	$	958		$	546
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)		822			748
Deferred income taxes and investment tax credits		399			301
Gains on the sale of assets and businesses		(71	)		(159	)
Charge associated with North Anna and offshore wind legislation		—			287
Other adjustments		(18	)		(55	)
Changes in:
Accounts receivable		214			153
Inventories		47			2
Deferred fuel and purchased gas costs, net (including write-off)		28			(322	)
Prepayments		47			(34	)
Accounts payable		(173	)		(258	)
Accrued interest, payroll and taxes		(41	)		(50	)
Margin deposit assets and liabilities		186			204
Other operating assets and liabilities		(238	)		84
Net cash provided by operating activities		2,160			1,447
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(2,370	)		(2,389	)
Acquisition of solar development projects		(230	)		(58	)
Acquisition of DCGT		(497	)		—
Proceeds from sales of securities		580			686
Purchases of securities		(553	)		(703	)
Proceeds from the sale of electric retail energy marketing business		—			187
Proceeds from the sale of assets to Blue Racer		—			84
Proceeds from assignments of Marcellus acreage		28			—
Other		(42	)		7
Net cash used in investing activities		(3,084	)		(2,186	)
Financing Activities
Issuance (repayment) of short-term debt, net		(153	)		1,152
Issuance of long-term debt		1,200			1,150
Repayment and repurchase of long-term debt		(8	)		(660	)
Subsidiary preferred stock redemption		—			(125	)
Issuance of common stock		647			71
Common dividend payments		(765	)		(698	)
Subsidiary preferred dividend payments		—			(6	)
Other		(44	)		(42	)
Net cash provided by financing activities		877			842
Increase (decrease) in cash and cash equivalents		(47	)		103
Cash and cash equivalents at beginning of period		318			316
Cash and cash equivalents at end of period	$	271		$	419
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	319		$	309

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

10

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
(millions)
Operating Revenue(1)	$	1,813	$	1,729	$	3,950	$	3,712
Operating Expenses
Electric fuel and other energy-related purchases(1)		497		518		1,307		1,168
Purchased electric capacity		90		87		184		175
Other operations and maintenance:
Affiliated suppliers		69		70		144		141
Other		376		563		697		833
Depreciation and amortization		231		217		469		435
Other taxes		69		69		143		142
Total operating expenses		1,332		1,524		2,944		2,894
Income from operations		481		205		1,006		818
Other income		21		21		36		36
Interest and related charges		108		103		216		210
Income before income tax expense		394		123		826		644
Income tax expense		148		54		311		251
Net Income		246		69		515		393
Preferred dividends		—		2		—		8
Balance available for common stock	$	246	$	67	$	515	$	385

(1) See Note 18 for amounts attributable to affiliates.

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

11

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
(millions)
Net income	$	246		$	69		$	515		$	393
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		7			(1	)		3			1
Changes in unrealized net gains on nuclear decommissioning trust funds(2)		—			6			1			8
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities(3)		—			(1	)		1			(4	)
Net realized gains on nuclear decommissioning trust funds(4)		(2	)		—			(3	)		(2	)
Other comprehensive income		5			4			2			3
Comprehensive income	$	251		$	73		$	517		$	396

(1) Net of $(4) million and $— million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $(2) million and $— million for the six months ended June 30, 2015 and 2014, respectively.

(2) Net of $1 million and $(3) million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $— million and $(5) million for the six months ended June 30, 2015 and 2014, respectively.

(3) Net of $— million tax for both the three months ended June 30, 2015 and 2014, and net of $— million and $2 million for the six months ended June 30, 2015 and 2014, respectively.

(4) Net of $1 million and $— million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $1 million for both the six months ended June 30, 2015 and 2014.

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

12

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2015			December 31, 2014(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	82		$	15
Customer receivables (less allowance for doubtful accounts of $28 and $25)		967			986
Other receivables (less allowance for doubtful accounts of $1 at both dates)		44			65
Inventories (average cost method)		828			853
Prepayments		23			252
Regulatory assets		317			298
Other(2)		33			82
Total current assets		2,294			2,551
Investments
Nuclear decommissioning trust funds		1,948			1,930
Other		4			4
Total investments		1,952			1,934
Property, Plant and Equipment
Property, plant and equipment		36,480			35,180
Accumulated depreciation and amortization		(11,431	)		(11,080	)
Total property, plant and equipment, net		25,049			24,100
Deferred Charges and Other Assets
Regulatory assets		447			439
Other(2)		551			485
Total deferred charges and other assets		998			924
Total assets	$	30,293		$	29,509

(1) Virginia Power’s Consolidated Balance Sheet at December 31, 2014 has been derived from the audited Consolidated Financial Statements at that date.

(2) See Note 18 for amounts attributable to affiliates.

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

13

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	June 30, 2015		December 31, 2014(1)
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	660	$	211
Short-term debt		1,441		1,361
Accounts payable		409		458
Payables to affiliates		93		92
Affiliated current borrowings		—		427
Accrued interest, payroll and taxes		241		199
Other		620		528
Total current liabilities		3,464		3,276
Long-Term Debt		8,970		8,726
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		4,385		4,415
Asset retirement obligations		1,018		848
Regulatory liabilities		1,774		1,683
Other(2)		380		506
Total deferred credits and other liabilities		7,557		7,452
Total liabilities		19,991		19,454
Commitments and Contingencies (see Note 16)
Common Shareholder’s Equity
Common stock – no par(3)		5,737		5,738
Other paid-in capital		1,113		1,113
Retained earnings		3,400		3,154
Accumulated other comprehensive income		52		50
Total common shareholder’s equity		10,302		10,055
Total liabilities and shareholder’s equity	$	30,293	$	29,509

(1) Virginia Power’s Consolidated Balance Sheet at December 31, 2014 has been derived from the audited Consolidated Financial Statements at that date.

(2) See Note 18 for amounts attributable to affiliates.

(3) 500,000 shares authorized; 274,723 shares outstanding at June 30, 2015 and December 31, 2014.

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

14

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,	2015			2014
(millions)
Operating Activities
Net income	$	515		$	393
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		555			521
Deferred income taxes and investment tax credits		13			246
Charge associated with North Anna and offshore wind legislation		—			287
Other adjustments		32			(17	)
Changes in:
Accounts receivable		40			26
Inventories		25			(31	)
Prepayments		229			(138	)
Deferred fuel expenses, net (including write-off)		(9	)		(359	)
Accounts payable		(8	)		18
Other operating assets and liabilities		2			(37	)
Net cash provided by operating activities		1,394			909
Investing Activities
Plant construction and other property additions		(1,292	)		(1,385	)
Purchases of nuclear fuel		(67	)		(131	)
Purchases of securities		(222	)		(311	)
Proceeds from sales of securities		209			299
Other		(27	)		(11	)
Net cash used in investing activities		(1,399	)		(1,539	)
Financing Activities
Issuance of short-term debt, net		80			481
Repayment of affiliated current borrowings, net		(427	)		(97	)
Issuance of long-term debt		700			750
Repayment of long-term debt		(6	)		(50	)
Preferred stock redemption		—			(125	)
Common dividend payments		(270	)		(270	)
Preferred dividend payments		—			(6	)
Other		(5	)		(11	)
Net cash provided by financing activities		72			672
Increase in cash and cash equivalents		67			42
Cash and cash equivalents at beginning of period		15			16
Cash and cash equivalents at end of period	$	82		$	58
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	117		$	236

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

15

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
(millions)
Operating Revenue(1)	$	395	$	428	$	926	$	997
Operating Expenses
Purchased gas(1)		21		76		95		213
Other energy-related purchases		7		5		13		21
Other operations and maintenance:
Affiliated suppliers		17		16		38		37
Other(2)		107		93		160		125
Depreciation and amortization		53		49		104		96
Other taxes		37		35		92		86
Total operating expenses		242		274		502		578
Income from operations		153		154		424		419
Other income		4		5		13		13
Interest and related charges		18		6		35		12
Income from operations before income taxes		139		153		402		420
Income tax expense		54		60		156		163
Net Income	$	85	$	93	$	246	$	257

(1) See Note 18 for amounts attributable to related parties.

(2) Includes gains on the sales of assets to related parties of $59 million for the six months ended June 30, 2014. See Note 10 for more information.

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

16

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
(millions)
Net income	$	85		$	93		$	246		$	257
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		3			(19	)		(1	)		(27	)
Changes in net unrecognized pension and other postretirement benefit costs(2)		—			—			—			(1	)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities(3)		(1	)		3			(1	)		8
Net pension and other postretirement benefit costs(4)		1			1			2			3
Other comprehensive income (loss)		3			(15	)		—			(17	)
Comprehensive income	$	88		$	78		$	246		$	240

(1) Net of $(1) million and $12 million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $1 million and $17 million tax for the six months ended June 30, 2015 and 2014, respectively.

(2) Net of $— million tax for both the three months ended June 30, 2015 and 2014, and net of $— million and $(1) million tax for the six months ended June 30, 2015 and 2014, respectively.

(3) Net of $— million and $(2) million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $— million and $(4) million tax for the six months ended June 30, 2015 and 2014, respectively.

(4) Net of $(1) million and $— million tax for the three months ended June 30, 2015 and 2014, respectively, and net of $(2) million and $(1) million tax for the six months ended June 30, 2015 and 2014, respectively.

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

17

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2015			December 31, 2014(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	11		$	9
Customer receivables (less allowance for doubtful accounts of $4 at both dates)(2)		222			322
Other receivables (less allowance for doubtful accounts of $1 at both dates)(2)		13			19
Affiliated receivables		7			12
Inventories		79			65
Prepayments		55			166
Other(2)		168			217
Total current assets		555			810
Investments		108			108
Property, Plant and Equipment
Property, plant and equipment		9,195			8,902
Accumulated depreciation and amortization		(2,609	)		(2,538	)
Total property, plant and equipment, net		6,586			6,364
Deferred Charges and Other Assets
Goodwill		542			542
Intangible assets, net		85			79
Regulatory assets		381			379
Pension and other postretirement benefit assets(2)		1,546			1,486
Other(2)		85			80
Total deferred charges and other assets		2,639			2,566
Total assets	$	9,888		$	9,848

(1) Dominion Gas’ Consolidated Balance Sheet at December 31, 2014 has been derived from the audited Consolidated Financial Statements at that date.

(2) See Note 18 for amounts attributable to related parties.

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

18

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	June 30, 2015			December 31, 2014(1)
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Short-term debt	$	360		$	—
Accounts payable		118			247
Payables to affiliates		21			41
Affiliated current borrowings		168			384
Accrued interest, payroll and taxes		140			194
Other(2)		162			172
Total current liabilities		969			1,038
Long-Term Debt		2,594			2,594
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,211			2,158
Other(2)		465			492
Total deferred credits and other liabilities		2,676			2,650
Total liabilities		6,239			6,282
Commitments and Contingencies (see Note 16)
Equity
Membership interests		3,735			3,652
Accumulated other comprehensive loss(2)		(86	)		(86	)
Total equity		3,649			3,566
Total liabilities and equity	$	9,888		$	9,848

(1) Dominion Gas’ Consolidated Balance Sheet at December 31, 2014 has been derived from the audited Consolidated Financial Statements at that date.

(2) See Note 18 for amounts attributable to related parties.

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

19

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,	2015			2014
(millions)
Operating Activities
Net income	$	246		$	257
Adjustments to reconcile net income to net cash provided by operating activities:
Gains on sales of assets		(71	)		(59	)
Depreciation and amortization		104			96
Deferred income taxes and investment tax credits		55			48
Other adjustments		—			(7	)
Changes in:
Accounts receivable		106			12
Deferred purchased gas costs, net		28			40
Prepayments		111			21
Inventories		(14	)		(18	)
Accounts payable		(132	)		(152	)
Payables to affiliates		(20	)		(32	)
Accrued interest, payroll and taxes		(54	)		(22	)
Other operating assets and liabilities		(66	)		(23	)
Net cash provided by operating activities		293			161
Investing Activities
Plant construction and other property additions		(292	)		(249	)
Proceeds from sale of assets to an affiliate		—			47
Proceeds from assignments of Marcellus acreage		28			—
Other		(6	)		(6	)
Net cash used in investing activities		(270	)		(208	)
Financing Activities
Issuance of short-term debt, net		360			—
Issuance (repayment) of affiliated current borrowings, net		(216	)		196
Distribution payments		(164	)		(145	)
Other		(1	)		(2	)
Net cash provided by (used in) financing activities		(21	)		49
Increase in cash and cash equivalents		2			2
Cash and cash equivalents at beginning of period		9			8
Cash and cash equivalents at end of period	$	11		$	10
Supplemental Cash Flow Information
Significant noncash investing and financing activities:
Accrued capital expenditures	$	37		$	40
Extinguishment of affiliated long-term debt in exchange for assets sold to affiliate		—			67

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

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 the Companies’ Annual Report on Form 10-K for the year ended December 31, 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, 2015, their results of operations for the three and six months ended June 30, 2015 and 2014, and their cash flows for the six months ended June 30, 2015 and 2014. 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, those of their respective majority-owned subsidiaries and non-wholly owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. As of June 30, 2015, Dominion owns the general partner and 70.9% of the limited partner interests in Dominion Midstream. The public’s ownership interest in Dominion Midstream is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. Also, as of June 30, 2015, Dominion owns 50% of the units in and consolidates Four Brothers. SunEdison’s ownership interest in Four Brothers is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. See Note 3 for more details regarding the nature and purpose of Four Brothers.

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’ 2014 Consolidated Financial Statements and Notes have been reclassified to conform to the 2015 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 Four Brothers

In June 2015, Dominion acquired 50% of the units in Four Brothers from SunEdison for approximately $64 million of consideration, consisting of $2 million in cash and a $62 million payable, which is included in other current liabilities in Dominion’s Consolidated Balance Sheets as of June 30, 2015. Four Brothers’ purpose is to develop and operate four solar projects located in Utah, which will produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $730 million to construct, including the initial acquisition cost. Dominion is obligated to contribute $445 million of capital to fund the construction of the projects. The facilities are expected to begin commercial operations in the third quarter of 2016, generating approximately 320 MW. Long-term power purchase, interconnection and operation and maintenance agreements have been executed for each of the projects. Dominion expects to claim 99% of the federal investment tax credits on the projects.

21

Dominion owns 50% of the voting interests in Four Brothers and has a controlling financial interest over the entity through its rights to control operations.

The allocation of the purchase price resulted in approximately $89 million of property, plant and equipment, $25 million of noncontrolling interest and $64 million of acquired equity. The noncontrolling interest was measured at fair value using the discounted cash flow method, with the primary components of the valuation being future cash flows (both incoming and outgoing) and the discount rate. Dominion determined its discount rate based on the cost of capital a utility-scale investor would expect, as well as the cost of capital an individual project developer could achieve via a combination of non-recourse project financing and outside equity partners.

Four Brothers has entered into agreements with SunEdison to provide administrative and support services in connection with the construction of the project, operation and maintenance of the facilities, and administrative and technical management services of the solar facilities. In addition, Dominion has entered into a contract with SunEdison to provide services related to construction project management and oversight. There have been no costs related to services to be provided under these agreements for the six months ended June 30, 2015.

Acquisitions of Solar Projects

The following table presents other significant acquisitions of solar projects by Dominion in 2014 and 2015. Long-term power purchase, interconnection and operation and maintenance agreements have been executed for all of the projects. Dominion has claimed and/or expects to claim federal investment tax credits on the projects.

Completed Acquisition Date	Seller	Number of Projects	Project Location	Project Name(s)	Initial Acquisition Cost (millions)			Project Cost (millions)(1)		Date of Commercial Operations	MW Capacity
March 2014	Recurrent Energy Development Holdings, LLC	6	California	Camelot, Kansas, Kent South, Old River One, Adams East, Columbia 2	$	50	(2)	$	446	Fourth quarter 2014		139
November 2014	CSI Project Holdco, LLC	1	California	West Antelope		79	(2)		80	November 2014		20
December 2014	EDF Renewable Development, Inc.	1	California	CID		71	(2)		71	January 2015		20
April 2015	EC&R NA Solar PV, LLC	1	California	Alamo		66	(2)		66	May 2015		20
April 2015	EDF Renewable Development, Inc.	3	California	City of Corcoran, Goose Lake, Marin Carport(3)		106	(2)		108	May 2015		24
June 2015	EDF Renewable Development, Inc.	1	California	Catalina 2		68	(4)		68	July 2015		18
July 2015	SunPeak Solar, LLC	1	California	Imperial Valley 2		42	(4)		70	Third quarter 2015		20

(1) Includes acquisition cost.

(2) The purchase price was primarily allocated to Property, Plant and Equipment.

(3) Marin Carport is expected to begin commercial operations in late 2015 or early 2016.

(4) The allocation of the purchase price to individual assets is under evaluation by management and has not been finalized.

In June 2015, Dominion entered into an agreement to acquire 100% of the equity interests in the Maricopa West solar project in California from EC&R NA Solar PV, LLC for approximately $65 million in cash. The project is expected to close in the fourth quarter of 2015 and cost approximately $66 million once constructed, including the initial acquisition cost. Upon completion, the facility is expected to generate approximately 20 MW.

The acquired assets of Four Brothers and the other solar projects are included in the Dominion Generation operating segment.

22

Acquisition of DCGT

In January 2015, Dominion completed the acquisition of 100% of the equity interests of DCGT from SCANA Corporation for approximately $497 million in cash, as adjusted for working capital. DCGT owns and operates nearly 1,500 miles of FERC-regulated interstate natural gas pipeline in South Carolina and southeastern Georgia. This acquisition supports Dominion’s natural gas expansion into the Southeast. The allocation of the purchase price is currently being evaluated and has preliminarily resulted in approximately $277 million of net property, plant and equipment, $250 million of goodwill, of which approximately $225 million is expected to be deductible for income tax purposes, and approximately $38 million of regulatory liabilities. The goodwill reflects the value associated with enhancing Dominion’s regulated gas position, economic value attributable to future expansion projects as well as increased opportunities for synergies. The acquired assets of DCGT are included in the Dominion Energy operating segment.

On March 24, 2015, DCGT converted to a limited liability company under the laws of South Carolina and changed its name from Carolina Gas Transmission Corporation to DCGT. On April 1, 2015, Dominion contributed 100% of the issued and outstanding membership interests of DCGT to Dominion Midstream in exchange for total consideration of $501 million, as adjusted for working capital. Total consideration to Dominion consisted of the issuance of a two-year, approximately $301 million senior unsecured promissory note payable by Dominion Midstream at an annual interest rate of 0.6%, and 5,112,139 common units, valued at $200 million, representing limited partner interests in Dominion Midstream. The number of units was based on the volume weighted average trading price of Dominion Midstream’s common units for the ten trading days prior to April 1, 2015, or $39.12 per unit. Since Dominion consolidates Dominion Midstream for financial reporting purposes, this transaction was eliminated upon consolidation and did not impact Dominion’s financial position or cash flows.

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.

Dominion Gas

Assignments of Marcellus Acreage

In December 2013, DTI closed an agreement with a natural gas producer to convey over time approximately 79,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provided for payments to DTI, subject to customary adjustments, of up to approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013 and 2014, DTI received approximately $98 million in cash proceeds. At December 31, 2014, deferred revenue totaled approximately $85 million. In March 2015, DTI and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of approximately 9,000 acres of Marcellus Shale development rights and a two year extension of the term of the original agreement. The conveyance of development rights resulted in the recognition of $43 million ($27 million after-tax) of previously deferred revenue to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. At June 30, 2015, deferred revenue totaled approximately $38 million, which is expected to be recognized over the remaining term of the agreement.

In March 2015, DTI conveyed to a natural gas producer approximately 11,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields and received proceeds of approximately $27 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in a $27 million ($16 million after-tax) gain, included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.

Dominion and Dominion Gas

Blue Racer

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

23

Note 4. Operating Revenue

The Companies’ operating revenue consists of the following:

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
(millions)
Dominion
Electric sales:
Regulated	$	1,779	$	1,697	$	3,891	$	3,648
Nonregulated		351		320		757		1,174
Gas sales:
Regulated		31		70		147		217
Nonregulated		87		228		295		345
Gas transportation and storage		385		351		856		795
Other		114		147		210		264
Total operating revenue	$	2,747	$	2,813	$	6,156	$	6,443
Virginia Power
Regulated electric sales	$	1,779	$	1,697	$	3,891	$	3,648
Other		34		32		59		64
Total operating revenue	$	1,813	$	1,729	$	3,950	$	3,712
Dominion Gas
Gas sales:
Regulated	$	21	$	54	$	78	$	137
Nonregulated		1		4		4		13
Gas transportation and storage		321		304		733		700
NGL revenue		22		44		51		101
Other		30		22		60		46
Total operating revenue	$	395	$	428	$	926	$	997

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,	2015			2014			2015			2014			2015			2014
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		3.3			1.5			3.8			3.8			3.9			3.7
Investment tax credits		(2.7	)		(4.9	)		—			—			—			—
Production tax credits		(0.8	)		(1.0	)		(0.5	)		(0.6	)		—			—
Valuation allowances		—			1.1			—			—			—			—
Other, net		(1.0	)		(0.4	)		(0.7	)		0.6			—			0.1
Effective tax rate		33.8	%		31.3	%		37.6	%		38.8	%		38.9	%		38.8	%

As of June 30, 2015, there have been no material changes in the Companies’ unrecognized tax benefits or possible changes that could reasonably be expected to occur during the next twelve months. See Note 5 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 for a discussion of these unrecognized tax benefits.

24

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,
	2015		2014		2015		2014
(millions, except EPS)
Net income attributable to Dominion	$	413	$	159	$	949	$	538
Average shares of common stock outstanding – Basic		591.5		581.9		589.7		581.7
Net effect of dilutive securities(1)		1.0		2.0		1.5		1.7
Average shares of common stock outstanding – Diluted		592.5		583.9		591.2		583.4
Earnings Per Common Share – Basic	$	0.70	$	0.27	$	1.61	$	0.92
Earnings Per Common Share – Diluted	$	0.70	$	0.27	$	1.60	$	0.92

(1) Dilutive securities consist primarily of the 2013 Equity Units for 2015 and contingently convertible senior notes and the 2013 Equity Units for 2014. See Note 15 in this report and Note 17 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 for more information.

The 2014 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and six months ended June 30, 2015, as the dilutive stock price threshold was not met. There were no potentially dilutive securities excluded from the calculation of diluted EPS for the three and six months ended June 30, 2014.

25

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, 2015
Beginning balance	$	(177	)	$	542		$	(769	)	$	(5	)	$	(409	)
Other comprehensive income before reclassifications: gains (losses)		92			(11	)		3			—			84
Amounts reclassified from AOCI(1): (gains) losses		(61	)		(12	)		12			—			(61	)
Net current-period other comprehensive income (loss)		31			(23	)		15			—			23
Ending balance	$	(146	)	$	519		$	(754	)	$	(5	)	$	(386	)
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 AOCI(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	)
Six Months Ended June 30, 2015
Beginning balance	$	(178	)	$	548		$	(782	)	$	(4	)	$	(416	)
Other comprehensive income before reclassifications: gains (losses)		34			4			3			(1	)		40
Amounts reclassified from AOCI(1): (gains) losses		(2	)		(33	)		25			—			(10	)
Net current-period other comprehensive income (loss)		32			(29	)		28			(1	)		30
Ending balance	$	(146	)	$	519		$	(754	)	$	(5	)	$	(386	)
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 AOCI(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	)

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

26

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, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(107	)	Operating revenue
		2		Purchased gas
Interest rate contracts		3		Interest and related charges
		(102	)
Tax		41		Income tax expense
	$	(61	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(25	)	Other income
Impairment		5		Other income
		(20	)
Tax		8		Income tax expense
	$	(12	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(3	)	Other operations and maintenance
Actuarial (gains) losses		24		Other operations and maintenance
		21
Tax		(9	)	Income tax expense
	$	12
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

27

Six Months Ended June 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(15	)	Operating revenue
		7		Purchased gas
		(1	)	Electric fuel and other energy-related purchases
Interest rate contracts		5		Interest and related charges
		(4	)
Tax		2		Income tax expense
	$	(2	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(64	)	Other income
Impairment		11		Other income
		(53	)
Tax		20		Income tax expense
	$	(33	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(6	)	Other operations and maintenance
Actuarial (gains) losses		49		Other operations and maintenance
		43
Tax		(18	)	Income tax expense
	$	25
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
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

28

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, 2015
Beginning balance	$	(24	)	$	(65	)	$	(89	)
Other comprehensive income before reclassifications: gains (losses)		3			—			3
Amounts reclassified from AOCI(1): (gains) losses		(1	)		1			—
Net current-period other comprehensive income		2			1			3
Ending balance	$	(22	)	$	(64	)	$	(86	)
Three Months Ended June 30, 2014
Beginning balance	$	—		$	(60	)	$	(60	)
Other comprehensive income before reclassifications: gains (losses)		(19	)		—			(19	)
Amounts reclassified from AOCI(1): (gains) losses		3			1			4
Net current-period other comprehensive income (loss)		(16	)		1			(15	)
Ending balance	$	(16	)	$	(59	)	$	(75	)
Six Months Ended June 30, 2015
Beginning balance	$	(20	)	$	(66	)	$	(86	)
Other comprehensive income before reclassifications: gains (losses)		(1	)		—			(1	)
Amounts reclassified from AOCI(1): (gains) losses		(1	)		2			1
Net current-period other comprehensive income (loss)		(2	)		2			—
Ending balance	$	(22	)	$	(64	)	$	(86	)
Six Months Ended June 30, 2014
Beginning balance	$	3		$	(61	)	$	(58	)
Other comprehensive income before reclassifications: gains (losses)		(27	)		(1	)		(28	)
Amounts reclassified from AOCI(1): (gains) losses		8			3			11
Net current-period other comprehensive income (loss)		(19	)		2			(17	)
Ending balance	$	(16	)	$	(59	)	$	(75	)

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

29

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, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(1	)	Operating revenue
		(1	)
Tax		—		Income tax expense
	$	(1	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	2		Other operations and maintenance
		2
Tax		(1	)	Income tax expense
	$	1
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
Six Months Ended June 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(1	)	Operating revenue
		(1	)
Tax		—		Income tax expense
	$	(1	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	4		Other operations and maintenance
		4
Tax		(2	)	Income tax expense
	$	2
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

30

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 the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. See Note 9 in this report for further information about the Companies’ 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 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, credit spreads 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 Dominion’s quantitative information about Level 3 fair value measurements at June 30, 2015. The range and weighted average are presented in dollars for market price inputs and percentages for credit spreads and price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input			Range	Weighted Average(1)
Assets:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	57	Discounted Cash Flow		Market Price (per Dth)	(3)	(2) - 4		(1	)
					Credit spread	(4)	1% - 5%		3	%
FTRs		25	Discounted Cash Flow		Market Price (per MWh)	(3)	(2) - 10		2
Physical and Financial Options:
Natural Gas		4	Option Model		Market Price (per Dth)	(3)	2 - 4		3
					Price Volatility	(5)	22% - 69%		33	%
Total assets	$	86
Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas(2)	$	10	Discounted Cash Flow		Market Price (per Dth)	(3)	(2) - 4		2
NGLs(6)		1	Discounted Cash Flow		Market Price (per Gal)	(3)	1 - 2		1
FTRs		2	Discounted Cash Flow		Market Price (per MWh)	(3)	(10) - 10		1
Physical and Financial Options:
Natural Gas		2	Option Model		Market Price (per Dth)	(3)	2 - 4		3
					Price Volatility	(5)	22% - 69%		33	%
Total liabilities	$	15

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents credit spreads unrepresented in published markets.

(5) Represents volatilities unrepresented in published markets.

(6) Information represents Dominion Gas’ quantitative information about Level 3 fair value measurement.

31

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)
Credit spread	Asset	Increase (decrease)	Loss (gain)

32

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, 2015
Assets:
Derivatives:
Commodity	$	1	$	452	$	86	$	539
Interest rate		—		58		—		58
Investments(1):
Equity securities:
U.S.:
Large cap		2,640		—		—		2,640
Other		7		—		—		7
Non-U.S.:
Large cap		13		—		—		13
Fixed income:
Corporate debt instruments		—		464		—		464
U.S. Treasury securities and agency debentures		399		179		—		578
State and municipal		—		412		—		412
Other		—		109		—		109
Cash equivalents and other		1		6		—		7
Total assets	$	3,061	$	1,680	$	86	$	4,827
Liabilities:
Derivatives:
Commodity	$	1	$	329	$	15	$	345
Interest rate		—		108		—		108
Total liabilities	$	1	$	437	$	15	$	453
At December 31, 2014
Assets:
Derivatives:
Commodity	$	3	$	567	$	125	$	695
Interest rate		—		24		—		24
Investments(1):
Equity securities:
U.S.:
Large cap		2,669		—		—		2,669
Other		6		—		—		6
Non-U.S.:
Large cap		12		—		—		12
Fixed income:
Corporate debt instruments		—		441		—		441
U.S. Treasury securities and agency debentures		419		190		—		609
State and municipal		—		395		—		395
Other		—		74		—		74
Cash equivalents and other		3		10		—		13
Total assets	$	3,112	$	1,701	$	125	$	4,938
Liabilities:
Derivatives:
Commodity	$	3	$	571	$	18	$	592
Interest rate		—		202		—		202
Total liabilities	$	3	$	773	$	18	$	794

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

33

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,
	2015			2014			2015			2014
(millions)
Beginning balance	$	76		$	8		$	107		$	(16	)
Total realized and unrealized gains (losses):
Included in earnings		(5	)		(10	)		10			100
Included in other comprehensive income (loss)		(1	)		(1	)		(12	)		3
Included in regulatory assets/liabilities		(5	)		(3	)		(29	)		14
Settlements		6			9			(8	)		(99	)
Transfers out of Level 3(1)		—			—			3			1
Ending balance	$	71		$	3		$	71		$	3
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	$	—		$	—		$	—		$	1

(1) In March 2015, Dominion changed the classification of certain short term NGL derivatives from Level 3 to Level 2 due to an increase in liquidity in financial forward markets. The transfers out of Level 3 that relate to NGLs for the three and six months ended June 30, 2015 are $— million and $9 million, respectively.

34

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, 2015
Total gains (losses) included in earnings	$	—		$	—		$	(5	)	$	(5	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		—			—			—			—
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	)		—			—
Six Months Ended June 30, 2015
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		1			—			(1	)		—
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

Virginia Power

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at June 30, 2015. The range and weighted average are presented in dollars for market price inputs and percentages for credit spreads.

	Fair Value (millions)		Valuation Techniques	Unobservable Input			Range	Weighted Average(1)
Assets:
Physical and Financial Forwards and Futures:
FTRs	$	25	Discounted Cash Flow		Market Price (per MWh)	(3)	(2) - 10		2
Natural Gas(2)		50	Discounted Cash Flow		Market Price (per Dth)	(3)	(2) - 3		(1	)
					Credit spread	(4)	1% - 5%		3	%
Total assets	$	75
Liabilities:
Physical and Financial Forwards and Futures:
FTRs	$	2	Discounted Cash Flow		Market Price (per MWh)	(3)	(10) - 10		1
Total liabilities	$	2

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents credit spreads unrepresented in published markets.

35

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)
Credit spread	Asset	Increase (decrease)	Loss (gain)

36

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, 2015
Assets:
Derivatives:
Commodity	$	—	$	5	$	75	$	80
Interest rate		—		37		—		37
Investments(1):
Equity securities:
U.S. large cap		1,170		—		—		1,170
Fixed income:
Corporate debt instruments		—		255		—		255
U.S. Treasury securities and agency debentures		140		60		—		200
State and municipal		—		217		—		217
Other		—		28		—		28
Total assets	$	1,310	$	602	$	75	$	1,987
Liabilities:
Derivatives:
Commodity	$	—	$	3	$	2	$	5
Interest rate		—		16		—		16
Total liabilities	$	—	$	19	$	2	$	21
At December 31, 2014
Assets:
Derivatives:
Commodity	$	—	$	7	$	106	$	113
Investments(1):
Equity securities:
U.S. large cap		1,157		—		—		1,157
Fixed income:
Corporate debt instruments		—		250		—		250
U.S. Treasury securities and agency debentures		137		61		—		198
State and municipal		—		211		—		211
Other		—		23		—		23
Total assets	$	1,294	$	552	$	106	$	1,952
Liabilities:
Derivatives:
Commodity	$	—	$	11	$	4	$	15
Interest rate		—		72		—		72
Total liabilities	$	—	$	83	$	4	$	87

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

37

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,
	2015			2014			2015			2014
(millions)
Beginning balance	$	78		$	10		$	102		$	(7	)
Total realized and unrealized gains (losses):
Included in earnings		(5	)		(9	)		8			111
Included in regulatory assets/liabilities		(5	)		(3	)		(29	)		14
Settlements		5			9			(8	)		(111	)
Ending balance	$	73		$	7		$	73		$	7

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, 2015 and 2014. 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, 2015 and 2014.

Dominion Gas

The following table presents Dominion Gas’ assets and liabilities for derivatives 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, 2015
Assets:
Commodity	$	—	$	6	$	—	$	6
Total Assets	$	—	$	6	$	—	$	6
Liabilities:
Commodity	$	—	$	5	$	1	$	6
Interest rate		—		9		—		9
Total liabilities	$	—	$	14	$	1	$	15
At December 31, 2014
Assets:
Commodity	$	—	$	—	$	2	$	2
Total Assets	$	—	$	—	$	2	$	2
Liabilities:
Interest rate	$	—	$	9	$	—	$	9
Total liabilities	$	—	$	9	$	—	$	9

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,
	2015			2014			2015			2014
(millions)
Beginning balance	$	—		$	(2	)	$	2		$	(6	)
Total realized and unrealized gains (losses):
Included in earnings		(1	)		(2	)		1			(7	)
Included in other comprehensive income (loss)		—			(1	)		(12	)		3
Settlements		—			2			(1	)		7
Transfers out of Level 3(1)		—			—			9			—
Ending balance	$	(1	)	$	(3	)	$	(1	)	$	(3	)

(1) In March 2015, Dominion changed the classification of certain short term NGL derivatives from Level 3 to Level 2 due to an increase in liquidity in financial forward markets. The transfers out of Level 3 that relate to NGLs for the three and six months ended June 30, 2015 are $— million and $9 million, respectively.

38

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, 2015 and 2014. 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, 2015 and 2014.

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, restricted cash (which is recorded in other current assets), 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, 2015				December 31, 2014
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)(3)	$	20,907	$	22,251	$	19,723	$	21,881
Junior subordinated notes(3)		1,373		1,348		1,374		1,396
Remarketable subordinated notes(3)		2,084		2,116		2,083		2,362
Virginia Power
Long-term debt, including securities due within one year(3)	$	9,630	$	10,541	$	8,937	$	10,293
Dominion Gas
Long-term debt(3)	$	2,594	$	2,614	$	2,594	$	2,672

(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) At June 30, 2015 and December 31, 2014, includes the valuation of certain fair value hedges associated with fixed rate debt of approximately $8 million and $19 million, respectively.

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

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 the Companies’ Annual Report on Form 10-K for the year ended December 31, 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 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’ and Virginia Power’s derivative contracts consist of over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a counterparty. 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.

39

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, 2015						December 31, 2014
	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	$	58	$	—	$	58	$	24	$	—	$	24
Commodity contracts:
Over-the-counter		276		—		276		382		—		382
Exchange		253		—		253		298		—		298
Total derivatives, subject to a master netting or similar arrangement		587		—		587		704		—		704
Total derivatives, not subject to a master netting or similar arrangement		10		—		10		15		—		15
Total	$	597	$	—	$	597	$	719	$	—	$	719

			June 30, 2015								December 31, 2014
			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	$	58	$	25	$	—	$	33	$	24	$	16	$	—	$	8
Commodity contracts:
Over-the-counter		276		30		17		229		382		34		34		314
Exchange		253		247		—		6		298		298		—		—
Total	$	587	$	302	$	17	$	268	$	704	$	348	$	34	$	322

40

	June 30, 2015						December 31, 2014
	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	$	108	$	—	$	108	$	202	$	—	$	202
Commodity contracts:
Over-the-counter		65		—		65		87		—		87
Exchange		272		—		272		493		—		493
Total derivatives, subject to a master netting or similar arrangement		445		—		445		782		—		782
Total derivatives, not subject to a master netting or similar arrangement		8		—		8		12		—		12
Total	$	453	$	—	$	453	$	794	$	—	$	794

			June 30, 2015								December 31, 2014
			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	$	108	$	25	$	—	$	83	$	202	$	16	$	—	$	186
Commodity contracts:
Over-the-counter		65		30		—		35		87		34		1		52
Exchange		272		247		25		—		493		298		195		—
Total	$	445	$	302	$	25	$	118	$	782	$	348	$	196	$	238

Volumes

The following table presents the volume of Dominion’s derivative activity as of June 30, 2015. 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)		50		13
Basis		217		570
Electricity (MWh):
Fixed price		12,920,765		5,146,901
FTRs		69,152,521		—
Capacity (MW)		16,800		—
Liquids (Gal)(2)		77,616,000		14,616,000
Interest rate	$	2,050,000,000	$	3,450,000,000

(1) Includes options.

(2) Includes NGLs and oil.

41

Ineffectiveness and AOCI

For the three and six months ended June 30, 2015 and 2014, 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, 2015:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12  Months After- Tax			Maximum Term
(millions)
Commodities:
Gas	$	(5	)	$	(5	)		28 months
Electricity		84			39			18 months
Other		(1	)		—			21 months
Interest rate		(224	)		(7	)		390 months
Total	$	(146	)	$	27

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.

42

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)
At June 30, 2015
ASSETS
Current Assets
Commodity	$	245	$	112	$	357
Interest rate		—		1		1
Total current derivative assets(1)		245		113		358
Noncurrent Assets
Commodity		107		75		182
Interest rate		57		—		57
Total noncurrent derivative assets(2)		164		75		239
Total derivative assets	$	409	$	188	$	597
LIABILITIES
Current Liabilities
Commodity	$	191	$	94	$	285
Interest rate		90		—		90
Total current derivative liabilities(3)		281		94		375
Noncurrent Liabilities
Commodity		37		23		60
Interest Rate		18		—		18
Total noncurrent derivative liabilities(4)		55		23		78
Total derivative liabilities	$	336	$	117	$	453
At December 31, 2014
ASSETS
Current Assets
Commodity	$	281	$	242	$	523
Interest rate		13		—		13
Total current derivative assets(1)		294		242		536
Noncurrent Assets
Commodity		71		101		172
Interest rate		11		—		11
Total noncurrent derivative assets(2)		82		101		183
Total derivative assets	$	376	$	343	$	719
LIABILITIES
Current Liabilities
Commodity	$	224	$	267	$	491
Interest rate		100		—		100
Total current derivative liabilities(3)		324		267		591
Noncurrent Liabilities
Commodity		55		46		101
Interest rate		102		—		102
Total noncurrent derivative liabilities(4)		157		46		203
Total derivative liabilities	$	481	$	313	$	794

43

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

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

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

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified from AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended June 30, 2015
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	107
Purchased gas					(2	)
Total commodity	$	94		$	105		$	—
Interest rate(3)		57			(3	)		91
Total	$	151		$	102		$	91
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	)
Six Months Ended June 30, 2015
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	15
Purchased gas					(7	)
Electric fuel and other energy-related purchases					1
Total commodity	$	54		$	9		$	3
Interest rate(3)		(1	)		(5	)		42
Total	$	53		$	4		$	45
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	)

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

44

(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.

	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	2015			2014			2015			2014
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	15		$	(1	)	$	18		$	(362	)
Purchased gas		(7	)		—			(9	)		6
Electric fuel and other energy-related purchases		3			(8	)		9			125
Total	$	11		$	(9	)	$	18		$	(231	)

(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, 2015						December 31, 2014
	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	$	37	$	—	$	37	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		75		—		75		106		—		106
Total derivatives, subject to a master netting or similar arrangement		112		—		112		106		—		106
Total derivatives, not subject to a master netting or similar arrangement		5		—		5		7		—		7
Total	$	117	$	—	$	117	$	113	$	—	$	113

			June 30, 2015								December 31, 2014
			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	$	37	$	6	$	—	$	31	$	—	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		75		2		—		73		106		4		—		102
Total	$	112	$	8	$	—	$	104	$	106	$	4	$	—	$	102

45

	June 30, 2015						December 31, 2014
	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	$	16	$	—	$	16	$	72	$	—	$	72
Commodity contracts:
Over-the-counter		2		—		2		8		—		8
Total derivatives, subject to a master netting or similar arrangement		18		—		18		80		—		80
Total derivatives, not subject to a master netting or similar arrangement		3		—		3		7		—		7
Total	$	21	$	—	$	21	$	87	$	—	$	87

			June 30, 2015								December 31, 2014
			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	$	16	$	6	$	—	$	10	$	72	$	—	$	—	$	72
Commodity contracts:
Over-the-counter		2		2		—		—		8		4		—		4
Total	$	18	$	8	$	—	$	10	$	80	$	4	$	—	$	76

Volumes

The following table presents the volume of Virginia Power’s derivative activity as of June 30, 2015. 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)		11		—
Basis		92		515
Electricity (MWh):
FTRs		67,712,636		—
Capacity (MW)		16,800		—
Interest rate	$	450,000,000	$	750,000,000

(1) Includes options.

Ineffectiveness

For the three and six months ended June 30, 2015 and 2014, gains or losses on hedging instruments determined to be ineffective were not material.

46

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)
At June 30, 2015
ASSETS
Current Assets
Commodity	$	—	$	30	$	30
Total current derivative assets(1)		—		30		30
Noncurrent Assets
Commodity		—		50		50
Interest rate		37		—		37
Total noncurrent derivative assets(2)		37		50		87
Total derivative assets	$	37	$	80	$	117
LIABILITIES
Current Liabilities
Commodity	$	—	$	5	$	5
Interest rate		16		—		16
Total current derivative liabilities(3)		16		5		21
Total derivative liabilities	$	16	$	5	$	21
At December 31, 2014
ASSETS
Current Assets
Commodity	$	—	$	51	$	51
Total current derivative assets(1)		—		51		51
Noncurrent Assets
Commodity		—		62		62
Total noncurrent derivative assets(2)		—		62		62
Total derivative assets	$	—	$	113	$	113
LIABILITIES
Current Liabilities
Commodity	$	3	$	12	$	15
Interest rate		45		—		45
Total current derivative liabilities(3)		48		12		60
Noncurrent Liabilities
Interest rate		27		—		27
Total noncurrent derivative liabilities(4)		27		—		27
Total derivative liabilities	$	75	$	12	$	87

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

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

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

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

47

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, 2015
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	—
Total commodity	$	—		$	—		$	—
Interest rate(3)		11			—			91
Total	$	11		$	—		$	91
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	)
Six Months Ended June 30, 2015
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Total commodity	$	—		$	(1	)	$	3
Interest rate(3)		5			—			42
Total	$	5		$	(1	)	$	45
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	)

(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	2015		2014			2015		2014
(millions)
Derivative Type and Location of Gains (Losses)
Commodity(2)	$	5	$	(8	)	$	12	$	111
Total	$	5	$	(8	)	$	12	$	111

(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.

48

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, 2015						December 31, 2014
	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)
Commodity contracts:
Over-the-counter	$	6	$	—	$	6	$	2	$	—	$	2
Total derivatives, subject to a master netting or similar arrangement	$	6	$	—	$	6	$	2	$	—	$	2

			June 30, 2015								December 31, 2014
			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)
Commodity contracts:
Over-the-counter	$	6	$	6	$	—	$	—	$	2	$	—	$	—	$	2
Total	$	6	$	6	$	—	$	—	$	2	$	—	$	—	$	2

	June 30, 2015						December 31, 2014
	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	$	9	$	—	$	9	$	9	$	—	$	9
Commodity contracts:
Over-the-counter		6		—		6		—		—		—
Total derivatives, subject to a master netting or similar arrangement	$	15	$	—	$	15	$	9	$	—	$	9

49

			June 30, 2015								December 31, 2014
			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	$	9	$	—	$	—	$	9	$	9	$	—	$	—	$	9
Commodity contracts:
Over-the-counter		6		6		—		—		—		—		—		—
Total	$	15	$	6	$	—	$	9	$	9	$	—	$	—	$	9

Volumes

The following table presents the volume of Dominion Gas’ derivative activity as of June 30, 2015. 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		4		—
Basis		4		—
NGLs (Gal)		74,760,000		12,600,000
Interest rate	$	—	$	250,000,000

Ineffectiveness and AOCI

For the three and six months ended June 30, 2015 and 2014, 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, 2015:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax		Maximum Term
(millions)
Commodities:
NGLs	$	(1	)	$	—		21 months
Interest rate		(21	)		—		354 months
Total	$	(22	)	$	—

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.

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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, 2015
ASSETS
Current Assets
Commodity	$	3	$	3	$	6
Total current derivative assets(1)		3		3		6
Total derivative assets	$	3	$	3	$	6
LIABILITIES
Current Liabilities
Commodity	$	4	$	1	$	5
Total current derivative liabilities(2)		4		1		5
Noncurrent Liabilities
Commodity		1		—		1
Interest rate		9		—		9
Total noncurrent derivative liabilities(3)		10		—		10
Total derivative liabilities	$	14	$	1	$	15
At December 31, 2014
ASSETS
Current Assets
Commodity	$	2	$	—	$	2
Total current derivative assets(1)		2		—		2
Total derivative assets	$	2	$	—	$	2
LIABILITIES
Noncurrent Liabilities
Interest rate	$	9	$	—	$	9
Total noncurrent derivative liabilities(3)		9		—		9
Total derivative liabilities	$	9	$	—	$	9

(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, 2015
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	1
Total commodity	$	—		$	1
Interest rate(2)		4			—
Total	$	4		$	1
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	)
Six Months Ended June 30, 2015
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	1
Total commodity	$	(2	)	$	1
Total	$	(2	)	$	1
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	)

(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.

	Amount of Gain (Loss) Recognized in Income on Derivatives
	Three Months Ended June 30,				Six Months Ended June 30,
Derivatives not designated as hedging instruments	2015		2014		2015		2014
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	3	$	—	$	4	$	—
Total	$	3	$	—	$	4	$	—

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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 $104 million and $110 million at June 30, 2015 and December 31, 2014, respectively. Cost method investments held in Dominion’s rabbi trusts totaled $5 million and $6 million at June 30, 2015 and December 31, 2014, 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)
At June 30, 2015
Marketable equity securities:
U.S. large cap	$	1,291	$	1,310	$	—		$	2,601
Marketable debt securities:
Corporate bonds		455		13		(4	)		464
U.S. Treasury securities and agency debentures		569		10		(2	)		577
State and municipal		355		16		(2	)		369
Other		108		—		—			108
Cost method investments		74		—		—			74
Cash equivalents and other(2)		15		—		—			15
Total	$	2,867	$	1,349	$	(8	)(3)	$	4,208
At December 31, 2014
Marketable equity securities:
U.S. large cap	$	1,273	$	1,353	$	—		$	2,626
Marketable debt securities:
Corporate bonds		424		19		(2	)		441
U.S. Treasury securities and agency debentures		597		13		(4	)		606
State and municipal		332		23		—			355
Other		66		—		—			66
Cost method investments		86		—		—			86
Cash equivalents and other(2)		16		—		—			16
Total	$	2,794	$	1,408	$	(6	)(3)	$	4,196

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

(2) Includes pending sales of securities of $8 million and $3 million at June 30, 2015 and December 31, 2014, respectively.

(3) The fair value of securities in an unrealized loss position was $500 million and $379 million at June 30, 2015 and December 31, 2014, respectively.

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The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at June 30, 2015 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	218
Due after one year through five years		372
Due after five years through ten years		434
Due after ten years		494
Total	$	1,518

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,
	2015		2014		2015		2014
(millions)
Proceeds from sales	$	243	$	244	$	580	$	686
Realized gains(1)		44		25		100		63
Realized losses(1)		12		7		29		13

(1) Includes realized gains and losses recorded to the nuclear 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, 2015 and 2014.

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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)
At June 30, 2015
Marketable equity securities:
U.S. large cap	$	586	$	583	$	—		$	1,169
Marketable debt securities:
Corporate bonds		252		6		(3	)		255
U.S. Treasury securities and agency debentures		199		2		(1	)		200
State and municipal		208		9		(1	)		216
Other		28		—		—			28
Cost method investments		74		—		—			74
Cash equivalents and other(2)		6		—		—			6
Total	$	1,353	$	600	$	(5	)(3)	$	1,948
At December 31, 2014
Marketable equity securities:
U.S. large cap	$	563	$	594	$	—		$	1,157
Marketable debt securities:
Corporate bonds		242		9		(1	)		250
U.S. Treasury securities and agency debentures		197		3		(2	)		198
State and municipal		197		13		—			210
Other		23		—		—			23
Cost method investments		86		—		—			86
Cash equivalents and other(2)		6		—		—			6
Total	$	1,314	$	619	$	(3	)(3)	$	1,930

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

(2) Includes pending sales of securities of $6 million at both June 30, 2015 and December 31, 2014.

(3) The fair value of securities in an unrealized loss position was $254 million and $170 million at June 30, 2015 and December 31, 2014, respectively.

The fair value of Virginia Power’s marketable debt securities held in nuclear decommissioning trust funds at June 30, 2015 by contractual maturity is as follows:

	Amount
(millions)
Due in one year or less	$	62
Due after one year through five years		153
Due after five years through ten years		252
Due after ten years		232
Total	$	699

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
(millions)
Proceeds from sales	$	76	$	95	$	209	$	299
Realized gains(1)		19		10		37		29
Realized losses(1)		4		3		15		6

(1) Includes realized gains and losses recorded to the nuclear 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, 2015 and 2014.

Equity Method Investments

Dominion Gas

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

Company	Ownership%			Investment Balance				Description
				June 30, 2015		December 31, 2014
(millions)
Iroquois		24.72	%	$	107	$	107	Gas transmission system
Total				$	107	$	107

Dominion Gas’ equity earnings on this investment totaled $12 million and $13 million for the six months ended June 30, 2015 and 2014, respectively. Dominion Gas received distributions from this investment of $12 million and $5 million for the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015 and December 31, 2014, the carrying amount of Dominion Gas’ investment exceeded its share of underlying equity in net assets by approximately $8 million. 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.

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 long-term debt 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 Statements of Income.

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Note 11. Regulatory Assets and Liabilities

Regulatory assets and liabilities include the following:

	June 30, 2015		December 31, 2014
(millions)
Dominion
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	115	$	79
Deferred rate adjustment clause costs(2)		85		124
Deferred nuclear refueling outage costs(3)		76		44
Unrecovered gas costs(4)		1		36
Other		63		64
Regulatory assets-current(5)		340		347
Unrecognized pension and other postretirement benefit costs(6)		1,017		1,050
Deferred rate adjustment clause costs(2)		300		250
Income taxes recoverable through future rates(7)		137		133
Derivatives(8)		56		101
Other		115		108
Regulatory assets-non-current		1,625		1,642
Total regulatory assets	$	1,965	$	1,989
Regulatory liabilities:
PIPP(9)	$	53	$	71
Other		52		99
Regulatory liabilities-current(10)		105		170
Provision for future cost of removal and AROs(11)		1,103		1,072
Nuclear decommissioning trust(12)		813		815
Other		214		104
Regulatory liabilities-non-current		2,130		1,991
Total regulatory liabilities	$	2,235	$	2,161
Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	115	$	79
Deferred nuclear refueling outage costs(3)		76		44
Deferred rate adjustment clause costs(2)		67		117
Other		59		58
Regulatory assets-current		317		298
Deferred rate adjustment clause costs(2)		223		179
Income taxes recoverable through future rates(7)		104		100
Derivatives(8)		56		101
Other		64		59
Regulatory assets-non-current		447		439
Total regulatory assets	$	764	$	737
Regulatory liabilities:
Other	$	31	$	90
Regulatory liabilities-current(10)		31		90
Provision for future cost of removal(11)		865		852
Nuclear decommissioning trust(12)		813		815
Other		96		16
Regulatory liabilities-non-current		1,774		1,683
Total regulatory liabilities	$	1,805	$	1,773

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Dominion Gas
Regulatory assets:
Deferred rate adjustment clause costs(2)	$	18	$	7
Unrecovered gas costs(4)		1		29
Other		1		2
Regulatory assets-current(5)		20		38
Unrecognized pension and other postretirement benefit costs(6)		235		242
Deferred rate adjustment clause costs(2)		77		71
Income taxes recoverable through future rates(7)		24		24
Other		45		42
Regulatory assets-non-current		381		379
Total regulatory assets	$	401	$	417
Regulatory liabilities:
PIPP(9)	$	53	$	71
Other		14		4
Regulatory liabilities-current(10)		67		75
Provision for future cost of removal and AROs(11)		175		172
Other		32		20
Regulatory liabilities-non-current(13)		207		192
Total regulatory liabilities	$	274	$	267

(1) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power’s generation operations. See Note 12 for more information.

(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, not to exceed 18 months.

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

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

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

(7) Amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes.

(8) 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 passed on to customers based on the ultimate settlement amount of the derivative.

(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.

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

At June 30, 2015, approximately $123 million of Dominion’s, $105 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 two years.

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

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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 PJM, MISO, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Tennessee, Georgia and California 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 be allocated to each wholesale transmission customer in Virginia. While Virginia Power cannot predict the outcome of the hearing, it is not expected to have a material effect on results of operations.

PJM Transmission Rates

In April 2007, FERC issued an order regarding its transmission rate design for the allocation of costs among PJM transmission customers, including Virginia Power, for transmission service provided by PJM. For new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a PJM regional rate design where customers pay according to each customer’s share of the region’s load. For recovery of costs of existing facilities, FERC approved the existing methodology whereby a customer pays the cost of facilities located in the same zone as the customer. A number of parties appealed the order to the U.S. Court of Appeals for the Seventh Circuit.

In August 2009, the court issued its decision affirming the FERC order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above for further consideration by FERC. On remand, FERC reaffirmed its earlier decision to allocate the costs of new facilities 500 kV and above according to the customer’s share of the region’s load. A number of parties filed appeals of the order to the U.S. Court of Appeals for the Seventh Circuit. In June 2014, the court again remanded the cost allocation issue to FERC. In December 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the cost allocation issue. The hearing only concerns

59

the costs of new facilities approved by PJM prior to February 1, 2013. Transmission facilities approved after February 1, 2013 are allocated on a hybrid cost allocation method approved by FERC and not subject to any court review. Settlement discussions are ongoing. Virginia Power anticipates that the majority of the impacts of any rate design changes resulting from the settlement discussions will be recoverable through retail rates in Virginia.

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 the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2015.

Virginia Regulation

Rate Adjustment Clauses

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

• The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2015, Virginia Power proposed an approximately $668 million total revenue requirement for the rate year beginning September 1, 2015, which represents an approximately $130 million increase over the previous year. Virginia Power also presented a mitigation proposal to defer approximately $96 million of this revenue requirement to the rate year beginning September 1, 2016, which would reduce by 50% the one-year rate impact on residential customers. In August 2015, the Virginia Commission rejected the mitigation proposal and approved full recovery of the proposed revenue requirement.

• The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2015, Virginia Power proposed an approximately $250 million revenue requirement for the rate year beginning April 1, 2016, which represents an approximately $5 million increase over the previous year. This case is pending.

• The Virginia Commission previously approved Rider W in conjunction with Warren County. In June 2015, Virginia Power proposed an approximately $118 million revenue requirement for the rate year beginning April 1, 2016, which represents an approximately $17 million decrease versus the previous year. This case is pending.

• The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In June 2015, Virginia Power proposed an approximately $74 million revenue requirement for the rate year beginning April 1, 2016, which represents an approximately $10 million decrease versus the previous year. This case is pending.

• The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2015, Virginia Power proposed an approximately $30 million revenue requirement for the rate year beginning April 1, 2016, which represents an approximately $21 million increase over the previous year. This case is pending.

• Virginia legislation which provides for the recovery of costs to move certain electric distribution facilities underground became effective in July 2014. In October 2014, Virginia Power filed for approval of Rider U, which proposed a revenue requirement of approximately $28 million during the initial rate year beginning September 1, 2015. In May 2015, Virginia Power revised the revenue requirement to $24 million. In July 2015, the Virginia Commission denied approval of Rider U based on the evidence in the record, but found that an alternative plan addressing certain concerns they had, such as the lack of a cost benefit analysis, could reasonably satisfy the regulatory requirements for approval. Virginia Power is reviewing the order and assessing its options, which could include filing such an alternative plan by year end.

Electric Transmission Project

In April 2015, the Supreme Court of Virginia issued its opinion in the consolidated appeals of the Virginia Commission’s order granting a CPCN for the Skiffes Creek transmission line and related facilities. The Supreme Court of Virginia unanimously affirmed all but one of the alleged grounds for appeal. The court approved the proposed project including the proposed route for a 500 kV overhead transmission line from Surry Power Station to the Skiffes Creek Switching Station site. The court reversed and remanded the Virginia Commission’s determination in one set of appeals that the Skiffes Creek Switching Station was a transmission line for purposes of statutory exemption from local zoning ordinances. In May 2015, the Supreme Court of Virginia denied separate petitions filed by Virginia Power and the Virginia Commission to rehear its ruling regarding the Skiffes Creek Switching Station. Pending receipt of remaining required permits and approvals, Virginia Power expects to construct the project.

North Anna

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. The COL is expected as early as 2016. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

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In September 2014, BREDL filed a petition with the NRC again seeking suspension of final decision making in the COL proceeding, along with motions to reopen and file a new contention. BREDL asserted that the NRC must make a safety finding on the feasibility and capacity of geologic disposal of spent fuel prior to the issuance of a license. BREDL also alleged that because these safety findings are no longer made as part of the NRC’s new continued storage rule, such findings must now be made in individual licensing proceedings. In January 2015, BREDL filed another petition asking the NRC to supplement the final environmental impact statement for North Anna 3 to incorporate the NRC’s generic assessment of the impacts of continued spent fuel storage, which would allow BREDL to then challenge that assessment.

The NRC denied the September 2014 petition and motions filed by BREDL in February 2015 and the January 2015 petition filed by BREDL in April 2015. In April 2015, BREDL filed a new motion and petition seeking to object to the NRC’s reliance on the continued storage rule in licensing proceedings. The BREDL filings are substantially the same as those filed in other COL proceedings in which final environmental impact statements were issued prior to promulgation of the continued storage rule, like North Anna 3. In June 2015, the NRC denied the April 2015 motion and petition.

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. 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 recognized additional charges of approximately $87 million ($57 million after-tax) ratably during the remainder of 2014, which are primarily included in other operations and maintenance expense in the Consolidated Statements of Income. 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 decided Virginia Power’s general rate case filed earlier that year, authorizing a 10.2% ROE. Following an appeal to the Supreme Court of North Carolina by multiple parties and a remand, the North Carolina Commission issued an opinion in July 2015 reaffirming its 10.2% ROE determination.

Ohio Regulation

PIPP Rider

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 amount is deferred and collected under the PIPP Rider in accordance with the rules of the Ohio Commission. In July 2015, 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 revised rider rate reflects the refund for the twelve-month period from July 2015 through June 2016 of an over-recovery of accumulated arrearages of approximately $57 million as of March 31, 2015, net of projected deferred program costs of approximately $35 million from April 2015 through June 2016.

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 2015, the Ohio Commission approved East Ohio’s application to decrease its UEX Rider, which reflects a refund of over-recovered accumulated bad debt expense of approximately $14 million as of March 31, 2015, and recovery of prospective net bad debt expense projected to total approximately $20 million for the twelve-month period from April 2015 to March 2016.

Note 13. Asset Retirement Obligations

AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of the Companies’ long-lived assets. Dominion’s and Virginia Power’s AROs are primarily associated with the decommissioning of their nuclear generation facilities and also include those for ash pond closures and the future abatement of asbestos expected to be disturbed in their generation facilities. Dominion Gas’ AROs primarily include plugging and abandonment of gas and oil wells and the interim retirement of natural gas gathering, transmission, distribution and storage pipeline components.

The Companies have also identified, but not recognized, AROs related to retirement of Dominion’s LNG facility, Dominion Gas’ storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in Dominion’s and Virginia Power’s generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected

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retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs for Dominion and Virginia Power during 2014 and 2015 are presented below. There were no significant changes to Dominion Gas’ AROs.

	Amount
(millions)
Dominion
AROs at December 31, 2013(1)	$	1,578
Obligations incurred during the period		40
Obligations settled during the period		(82	)
Revisions in estimated cash flows(2)		102
Accretion		81
Other		(5	)
AROs at December 31, 2014(1)	$	1,714
Obligations incurred during the period(3)		306
Obligations settled during the period		(38	)
Revisions in estimated cash flows(3)		34
Accretion		44
Other		(1	)
AROs at June 30, 2015(1)	$	2,059
Virginia Power
AROs at December 31, 2013	$	689
Obligations incurred during the period		28
Obligations settled during the period		(1	)
Revisions in estimated cash flows(2)		108
Accretion		37
Other		(6	)
AROs at December 31, 2014(4)	$	855
Obligations incurred during the period(3)		288
Obligations settled during the period		(2	)
Revisions in estimated cash flows(3)		34
Accretion		23
AROs at June 30, 2015(4)	$	1,198

(1) Includes $94 million, $81 million and $247 million reported in other current liabilities at December 31, 2013, December 31, 2014 and June 30, 2015, respectively.

(2) Relates primarily to a shift of the delayed planned date on which the DOE is expected to begin accepting spent nuclear fuel.

(3) Primarily reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 16 for further information.

(4) Includes $7 million and $180 million reported in other current liabilities at December 31, 2014 and June 30, 2015, respectively.

Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At June 30, 2015 and December 31, 2014, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $4.2 billion. At June 30, 2015 and December 31, 2014, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.9 billion.

Note 14. Variable Interest Entities

As discussed in Note 15 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, certain variable pricing terms in some of the Companies’ contracts cause them to be considered variable interests in the counterparties.

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Virginia Power

Virginia Power has long-term power and capacity contracts with five 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 $530 million as of June 30, 2015. Virginia Power paid $56 million and $55 million for electric capacity and $23 million and $33 million for electric energy to these entities in the three months ended June 30, 2015 and 2014, respectively. Virginia Power paid $108 million and $111 million for electric capacity and $60 million and $87 million for electric energy to these entities in the six months ended June 30, 2015 and 2014, respectively.

Virginia Power and Dominion Gas

Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of approximately $83 million and $30 million for the three months ended June 30, 2015, $106 million and $26 million for the three months ended June 30, 2014, $166 million and $58 million for the six months ended June 30, 2015, and $214 million and $52 million for the six months ended June 30, 2014, 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 15. 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.

Dominion

At June 30, 2015, 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	$	2,622	$	—	$	1,378
Joint revolving credit facility(2)		500		—		56		444
Total	$	4,500	$	2,622	$	56	$	1,822

(1) This credit facility has a maturity date of April 2019, and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.

(2) This credit facility has a maturity date of April 2019, and 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 the Companies and for other general corporate purposes.

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At June 30, 2015, 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		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Sub-limit Capacity Available
(millions)
Joint revolving credit facility(1)	$	1,500	$	1,441	$	—	$	59
Joint revolving credit facility(2)		250		—		—		250
Total	$	1,750	$	1,441	$	—	$	309

(1) This credit facility has a maturity date of April 2019, and 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. In January 2015, Virginia Power increased its sub-limit from $1.25 billion to $1.50 billion.

(2) This credit facility has a maturity date of April 2019, and 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.

In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility with a maturity date of April 2019. As of June 30, 2015, 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. In December 2014, Dominion Gas entered into a commercial paper program pursuant to which it began accessing the commercial paper markets in January 2015.

At June 30, 2015, Dominion Gas’ share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion and Virginia Power were as follows:

	Facility Sub-limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Sub-limit Capacity Available
(millions)
Joint revolving credit facility(1)	$	500	$	360	$	—	$	140
Joint revolving credit facility(2)		—		—		—		—
Total	$	500	$	360	$	—	$	140

(1) This credit facility has a maturity date of April 2019, and 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. Dominion Gas’ current sub-limit under this credit facility can be increased or decreased multiple times per year, up to a maximum of $1.0 billion.

(2) This credit facility has a maturity date of April 2019, and can be used to support bank borrowings, commercial paper and letter of credit issuances. Dominion Gas’ current sub-limit under this credit facility can be increased or decreased multiple times per year.

Long-term Debt

In May 2015, Virginia Power issued $350 million of 3.10% senior notes and $350 million of 4.20% senior notes that mature in 2025, and 2045, respectively.

In June 2015, Dominion issued $500 million of 1.90% senior notes that mature in 2018.

At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015. As a result, at December 31, 2014, the notes were included in securities due within one year in Dominion’s Consolidated Balance Sheets. The option to redeem the notes expired in June 2015. As of June 30, 2015, the notes were reclassified to long-term debt in Dominion’s Consolidated Balance Sheets.

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.

In December 2014, Dominion filed an SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at-the-market program. Also in December 2014, Dominion entered into four separate sales

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agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the NYSE at market prices or in such other transactions as are agreed upon by Dominion and the sales agents and in conformance with applicable securities laws. During the first quarter of 2015, Dominion provided sales instructions to the sales agents and issued 2.9 million shares through at-the-market issuances and received cash proceeds of approximately $219 million, net of fees and commissions paid of approximately $2 million. During the second quarter of 2015, Dominion provided sales instructions to the sales agents and issued 1.1 million shares through at-the-market issuances and received cash proceeds of approximately $78 million, net of fees and commissions paid of approximately $1 million. Following these issuances, Dominion has the ability to issue up to approximately $200 million of stock under the 2014 sales agency agreements. However, Dominion completed its 2015 planned market issuances of equity with the issuance of 2.8 million shares and receipt of proceeds of approximately $202 million through a registered underwritten public offering. Dominion has no current plans to issue to the market any additional shares of its common stock or other equity-linked securities in 2015.

Note 16. 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, 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 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 litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies’ maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial position, liquidity or results of operations of the Companies.

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.

In December 2011, the EPA issued MATS for coal- and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance was required by April 16, 2015, with certain limited exceptions. However, in June 2014, the VDEQ granted a one-year MATS compliance extension for two coal-fired units at Yorktown to defer planned retirements and allow for continued operation of the units to address reliability concerns while necessary electric transmission upgrades are being completed. Due to delays in transmission upgrades needed to maintain electric reliability, these coal units will need to continue operating until at least early 2017. Therefore, Virginia Power plans to request from the EPA an additional one year compliance extension under an EPA Administrative Order.

In June 2015, the U.S. Supreme Court issued a decision holding that the EPA failed to take cost into account when the agency first decided to regulate the emissions from coal- and oil-fired plants, and remanded the MATS rule back to the D.C. Circuit Court. However, the Supreme Court did not vacate or stay the effective date and implementation of the MATS rule. Therefore, the Supreme Court’s decision does not change Dominion’s plans to close coal units at Yorktown or the need to complete necessary electricity transmission upgrades by 2017. At this time, Dominion intends to proceed as scheduled, pending further action regarding the MATS rule by the D.C. Circuit Court.

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The EPA established CAIR with the intent to require significant reductions in SO₂ and NOx emissions from electric generating facilities. In July 2008, the U.S. Court of Appeals for the D.C. Circuit issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. In July 2011, the EPA issued a replacement rule for CAIR, called CSAPR, that required 28 states to reduce power plant emissions that cross state lines. CSAPR established new SO₂ and NOx emissions cap and trade programs that were completely independent of the current ARP. Specifically, CSAPR required reductions in SO₂ and NOx emissions from fossil fuel-fired electric generating units of 25 MW or more through annual NOx emissions caps, NOx 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 a successful motion for stay, in October 2014, the U.S. Court of Appeals for the D.C. Circuit ordered that the EPA’s motion to lift the stay of CSAPR be granted. Further, the Court granted the EPA’s request to shift the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets (which would have gone into effect in 2012 and 2013) will apply in 2015 and 2016, and Phase 2 emissions budgets will apply in 2017 and beyond. CSAPR replaced CAIR beginning in January 2015. The cost to comply is not expected to be material to the Consolidated Financial Statements. Future outcomes of any additional litigation and/or any action to issue a revised rule could affect the assessment regarding cost of compliance.

In May 2012, the EPA issued final designations for the 75-ppb ozone air quality standard. A number of the Companies’ facilities are located in areas impacted by this standard. As part of the standard, states will be required to develop and implement plans to address sources emitting pollutants which contribute to the formation of ozone. In November 2014, the EPA issued a new proposal to revise the ozone standard and expects to finalize the rule in October 2015. The EPA is not expected to complete attainment designations for a new standard until 2017 and states will have until 2020 to develop plans to address the new standard. Until the states have developed implementation plans, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significant expenditures are required to implement additional controls, it could adversely affect the Companies’ results of operations and cash flows.

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 compound 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 requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The Companies must comply with applicable aspects of the CWA programs at their operating facilities.

In October 2014, the 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 became effective. 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

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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. In February 2015, the NPDES permit renewal application was submitted to the Connecticut Department of Energy and Environmental Protection along with a schedule to update the evaluation of control technologies consistent with the new federal 316(b) rule. Dominion is currently unable to make an estimate of the potential financial statement impacts related to this matter.

Solid and Hazardous Waste

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

From time to time, Dominion, 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.

See below for discussion on ash pond closure costs.

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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. In July 2014, the EPA issued a memorandum specifying that it will no longer apply or enforce federal regulations or EPA-approved PSD state implementation plan provisions that require new and modified stationary sources to obtain a PSD permit when GHGs are the only pollutant that would be emitted at levels that exceed the permitting thresholds. In addition, the EPA stated that it will continue to use the existing thresholds to apply to sources that are otherwise subject to PSD for conventional pollutants until it completes a new rulemaking either justifying and upholding those thresholds or setting new ones. Some states have issued interim guidance that follows the EPA guidance. Due to uncertainty regarding what additional actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the court ruling under a new rulemaking, the Companies cannot predict the impact to their financial statements 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 three 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. The deferral policy expired in July 2014. 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 or the EPA’s final policy regarding the treatment of specific feedstock will affect biomass sources that were permitted during the deferral period; however, the expenditures to comply with any new requirements could be material to Dominion’s and Virginia Power’s financial statements.

Other Legal Matters

The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are 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.

Appalachian Gateway

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 as well as 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.

Ash Pond Closure Costs

In September 2014, Virginia Power received a notice from the SELC on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at Possum Point. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point’s historical and active ash storage facilities. A similar notice from the SELC on behalf of the Sierra Club was subsequently received related to Chesapeake. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum Point, Chesapeake and Bremo as settlement of the potential litigation. While the issue is open to potential further negotiations, the SELC declined the offer as presented in January 2015 and, in March 2015, filed a lawsuit related to its claims of the alleged CWA violations at Chesapeake. Virginia Power filed a motion to dismiss in April 2015. A ruling on the motion is pending. As a result of the settlement offer, Virginia Power recognized a charge of $121 million in other operations and maintenance expense in its Consolidated Statements of Income in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.

In April 2015, the EPA’s final rule regulating the management of CCRs stored in impoundments (ash ponds) and landfills was published in the Federal Register. The final rule regulates CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store CCRs. Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. The enactment of the final rule in April 2015 created a legal obligation for Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of

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time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary. In the second quarter of 2015, Virginia Power recorded a $325 million ARO related to future ash pond and landfill closure costs. Recognition of the ARO also resulted in a $45 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $159 million increase in property, plant, and equipment associated with asset retirement costs, and a $121 million reduction in other noncurrent liabilities related to reversal of the contingent liability described above since the ARO obligation created by the final CCR rule represents similar activities. The actual asset retirement costs related to the CCR rule may vary substantially from the estimates used to record the increased obligation in the second quarter, due to uncertainty about compliance strategies that will be used based on final requirements to be imposed by the various state regulators.

Nuclear Matters

In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as INPO. Like other U.S. nuclear operators, Dominion has been gathering supporting data and participating in industry initiatives focused on the ability to respond to and mitigate the consequences of design-basis and beyond-design-basis events at its stations.

In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011, the NRC staff prioritized these recommendations into Tiers 1, 2 and 3, with the Tier 1 recommendations consisting of actions which the staff determined should be started without unnecessary delay. In December 2011, the NRC Commissioners approved the agency staff’s prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.

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

Guarantees, Surety Bonds and Letters of Credit

Dominion

At June 30, 2015, Dominion had issued $74 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of June 30, 2015, Dominion’s exposure under these guarantees was $39 million, primarily related to certain reserve requirements associated with non-recourse financing.

Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion’s consolidated subsidiaries, that liability is included in 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.

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At June 30, 2015, Dominion had issued the following subsidiary guarantees:

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	27	$	27
Commodity transactions(3)		2,662		1,126
Nuclear obligations(4)		197		74
Cove Point(5)		1,910		—
Solar(6)		1,192		523
Other(7)		536		44
Total	$	6,524	$	1,794

(1) Represents the estimated portion of the guarantee’s stated limit that is utilized as of June 30, 2015 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount.

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

(3) Guarantees related to 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 the operating 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, in support of terminal services, transportation and construction. Two of the guarantees have no stated limit, one guarantee has a $150 million limit, and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million.

(6) Includes guarantees to facilitate the development of solar projects including guarantees to support the issuance of full notice to proceed under EPC agreements. Includes certain guarantees that do not have stated limits. Also includes guarantees entered into by DEI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.

(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. As of June 30, 2015, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $63 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits.

Additionally, at June 30, 2015, Dominion had purchased $132 million of surety bonds, including $66 million at Virginia Power and $30 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $56 million 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 17. Credit Risk

The Companies’ accounting policies for credit risk are discussed in Note 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.

At June 30, 2015, Dominion’s credit exposure related to energy marketing and price risk management activities totaled $276 million. Of this amount, investment grade counterparties, including those internally rated, represented 80%. No single counterparty, whether investment grade or non-investment grade, exceeded $35 million of 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, 2015 and December 31, 2014, Dominion would have been required to post an additional $18 million and $20 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 $71 million and $1 million in collateral at June 30, 2015 and December 31, 2014, respectively, related to

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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, 2015 and December 31, 2014 was $47 million and $49 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, 2015 and December 31, 2014. See Note 9 for further information about derivative instruments.

Dominion Gas

In the second quarter of 2015, DTI provided service to 242 customers with approximately 95% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 42% of total storage and transportation revenue and the thirty largest provided approximately 73% of total storage and transportation revenue. Approximately 99% of the transmission capacity under contract on DTI’s pipeline is subscribed with long-term contracts (two years or greater). The remaining 1% 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.

East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates approved by the Ohio Commission. Approximately 99% 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.

Note 18. 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 risks associated with purchases of natural gas. See Notes 7 and 9 for more information.

Virginia Power participates in certain Dominion benefit plans described in Note 19. In Virginia Power’s Consolidated Balance Sheets at June 30, 2015 and December 31, 2014, amounts due to Dominion associated with these benefit plans included in other deferred credits and other liabilities were $268 million and $219 million, respectively, and amounts due from Dominion at June 30, 2015 included in other deferred charges and other assets were $56 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 Virginia Power’s significant transactions with DRS and other affiliates:

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
(millions)
Commodity purchases from affiliates	$	94	$	113	$	346	$	315
Services provided by affiliates(1)		107		106		217		214
Services provided to affiliates		5		6		10		11

(1) Includes capitalized expenditures.

Virginia Power has borrowed funds from Dominion under short-term borrowing arrangements. Virginia Power had no short-term demand note borrowings from Dominion as of June 30, 2015. There were $427 million in short-term demand note borrowings from Dominion as of December 31, 2014. Virginia Power had no outstanding borrowings, net of repayments under the Dominion money pool for its nonregulated subsidiaries as of June 30, 2015 and December 31, 2014. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the three and six months ended June 30, 2015 and 2014.

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There were no issuances of Virginia Power’s common stock to Dominion for the three and six months ended June 30, 2015 or 2014.

Dominion Gas

Transactions with Related Parties

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, 2015 and December 31, 2014, all of Dominion Gas’ commodity derivatives were with affiliates. See Notes 7 and 9 for more information. See Note 10 for information regarding sales of assets to an affiliate.

Dominion Gas participates in certain Dominion benefit plans as described in Note 19.

DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Gas. Dominion Gas provides certain services to related parties, including technical services. The costs of these services follow:

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
(millions)
Purchases of natural gas and transportation and storage services from affiliates	$	2	$	6	$	4	$	8
Sales of natural gas and transportation and storage services to affiliates		17		21		35		46
Services provided by related parties(1)		35		25		69		51
Services provided to related parties		25		10		45		22

(1) Includes capitalized expenditures.

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

	June 30, 2015		December 31, 2014
(millions)
Other receivables(1)	$	6	$	17
Customer receivables from related parties		9		5
Imbalances receivable from affiliates(2)		2		3
Affiliated notes receivable(3)		12		9

(1) Represents amounts due from Atlantic Coast Pipeline, a related party VIE.

(2) Amounts are presented in other current assets 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 $168 million as of June 30, 2015 and $384 million as of December 31, 2014. Interest charges related to Dominion Gas’ total borrowings from Dominion were immaterial for the three and six months ended June 30, 2015 and 2014.

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Note 19. Employee Benefit Plans

Dominion

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

	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
(millions)
Three Months Ended June 30,
Service cost	$	31		$	28		$	10		$	8
Interest cost		72			73			16			16
Expected return on plan assets		(133	)		(125	)		(30	)		(27	)
Amortization of prior service cost (credit)		1			1			(6	)		(7	)
Amortization of net actuarial loss		40			28			2			1
Net periodic benefit cost (credit)	$	11		$	5		$	(8	)	$	(9	)
Six Months Ended June 30,
Service cost	$	63		$	57		$	20		$	16
Interest cost		144			145			33			33
Expected return on plan assets		(266	)		(250	)		(59	)		(55	)
Amortization of prior service cost (credit)		1			2			(13	)		(14	)
Amortization of net actuarial loss		80			56			3			1
Net periodic benefit cost (credit)	$	22		$	10		$	(16	)	$	(19	)

Employer Contributions

During the six months ended June 30, 2015, 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 2015.

Dominion Gas

Dominion Gas participates in certain Dominion benefit plans as described in Note 21 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. At June 30, 2015 and December 31, 2014, 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 $633 million and $614 million, respectively. At June 30, 2015 and December 31, 2014, 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 $5 million and $7 million, respectively.

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
	2015			2014			2015			2014
(millions)
Three Months Ended June 30,
Service cost	$	4		$	3		$	1		$	2
Interest cost		7			7			4			3
Expected return on plan assets		(32	)		(28	)		(6	)		(6	)
Amortization of prior service credit		—			—			—			(1	)
Amortization of net actuarial loss		5			4			—			—
Net periodic benefit credit	$	(16	)	$	(14	)	$	(1	)	$	(2	)
Six Months Ended June 30,
Service cost	$	7		$	6		$	3		$	3
Interest cost		14			14			7			6
Expected return on plan assets		(63	)		(57	)		(12	)		(11	)
Amortization of prior service credit		—			—			—			(1	)
Amortization of net actuarial loss		10			9			1			—
Net periodic benefit credit	$	(32	)	$	(28	)	$	(1	)	$	(3	)

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Employer Contributions

During the six months ended June 30, 2015, 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 2015.

Note 20. 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 for Dominion.

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.

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, 2015, Dominion reported an after-tax net expense of $64 million for specific items in the Corporate and Other segment, with $62 million of these net expenses attributable to its operating segments. 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.

The net expense for specific items in 2015 primarily related to the impact of the following items:

• An $85 million ($52 million after-tax) write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015, attributable to Dominion Generation;

• A $45 million ($28 million after-tax) charge related to incremental future ash pond and landfill closure costs at certain utility generation facilities due to the enactment of the final CCR rule in April 2015, attributable to Dominion Generation; and

• A $17 million ($10 million after-tax) billing adjustment related to PJM, attributable to Dominion Generation; partially offset by

• A $45 million ($28 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.

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

	DVP		Dominion Generation		Dominion Energy		Corporate and Other			Adjustments/ Eliminations			Consolidated Total
(millions)
Three Months Ended June 30, 2015
Total revenue from external customers	$	500	$	1,700	$	393	$	4		$	150		$	2,747
Intersegment revenue		5		12		163		144			(324	)		—
Total operating revenue		505		1,712		556		148			(174	)		2,747
Net income (loss) attributable to Dominion		117		250		129		(83	)		—			413
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
Six Months Ended June 30, 2015
Total revenue from external customers	$	1,064	$	3,822	$	772	$	(9	)	$	507		$	6,156
Intersegment revenue		10		38		523		286			(857	)		—
Total operating revenue		1,074		3,860		1,295		277			(350	)		6,156
Net income (loss) attributable to Dominion		257		532		336		(176	)		—			949
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

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, 2015, Virginia Power reported an after-tax net expense of $87 million for specific items in the Corporate and Other segment, all of which was attributable to its operating 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.

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The net expense for specific items in 2015 primarily related to the impact of the following items:

• An $85 million ($52 million after-tax) write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015, attributable to Dominion Generation;

• A $45 million ($28 million after-tax) charge related to incremental future ash pond and landfill closure costs at certain utility generation facilities due to the enactment of the final CCR rule in April 2015, attributable to Dominion Generation; and

• A $15 million ($9 million after-tax) billing adjustment related to PJM, attributable to Dominion Generation.

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.

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, 2015
Operating revenue	$	502	$	1,311	$	—		$	1,813
Net income (loss)		117		155		(26	)		246
Three Months Ended June 30, 2014
Operating revenue	$	448	$	1,281	$	—		$	1,729
Net income (loss)		117		133		(181	)		69
Six Months Ended June 30, 2015
Operating revenue	$	1,069	$	2,896	$	(15	)	$	3,950
Net income (loss)		257		345		(87	)		515
Six Months Ended June 30, 2014
Operating revenue	$	950	$	2,762	$	—		$	3,712
Net income (loss)		251		322		(180	)		393

Dominion Gas

The Corporate and Other Segment of Dominion Gas primarily 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, 2015 and 2014, Dominion Gas reported no amounts for specific items in the Corporate and Other segment.

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

	Dominion Energy		Corporate and Other			Consolidated Total
(millions)
Three Months Ended June 30, 2015
Operating revenue	$	395	$	—		$	395
Net income (loss)		87		(2	)		85
Three Months Ended June 30, 2014
Operating revenue	$	428	$	—		$	428
Net income (loss)		96		(3	)		93
Six Months Ended June 30, 2015
Operating revenue	$	926	$	—		$	926
Net income (loss)		251		(5	)		246
Six Months Ended June 30, 2014
Operating revenue	$	997	$	—		$	997
Net income (loss)		262		(5	)		257

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Contents of MD&A

MD&A consists of the following information:

• Forward-Looking Statements

• Accounting Matters - Dominion

• Dominion

• Results of Operations

• Segment Results of Operations

• Virginia Power

• Results of Operations

• Dominion Gas

• Results of Operations

• Liquidity and Capital Resources - Dominion

• Future Issues and Other Matters - Dominion

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;

• Changes in enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;

• Changes in regulator implementation of environmental standards and litigation exposure for remedial activities;

• Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals;

• 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;

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• Fluctuations in interest rates;

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

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

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

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

• Impacts of acquisitions, divestitures, transfers of assets to joint ventures or Dominion Midstream, 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 Dominion Midstream’s growth 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, changes in supplies of natural gas delivered to Dominion and Dominion Gas’ pipeline and processing systems, 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 development, construction and ownership of certain electric transmission facilities in Virginia Power’s service territory in connection with FERC Order 1000;

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

• Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion 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, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, 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 the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.

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, 2015 there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. 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 and employee benefit plans.

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Dominion

Results of Operations

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

	2015		2014		$ Change
(millions, except EPS)
Second Quarter
Net income attributable to Dominion	$	413	$	159	$	254
Diluted EPS		0.70		0.27		0.43
Year-To-Date
Net income attributable to Dominion	$	949	$	538	$	411
Diluted EPS		1.60		0.92		0.68

Overview

Second Quarter 2015 vs. 2014

Net income attributable to Dominion increased $254 million, primarily due to the absence of a 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.

Year-To-Date 2015 vs. 2014

Net income attributable to Dominion increased 76% primarily due to the absence of losses related to the repositioning of Dominion’s producer services business, which was completed in the first quarter of 2014, and the absence of a 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.

Analysis of Consolidated Operations

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

	Second Quarter							Year-To-Date
	2015		2014		$ Change			2015		2014		$ Change
(millions)
Operating revenue	$	2,747	$	2,813	$	(66	)	$	6,156	$	6,443	$	(287	)
Electric fuel and other energy-related purchases		591		633		(42	)		1,544		1,967		(423	)
Purchased electric capacity		90		87		3			184		175		9
Purchased gas		111		324		(213	)		361		864		(503	)
Net revenue		1,955		1,769		186			4,067		3,437		630
Other operations and maintenance		709		933		(224	)		1,311		1,358		(47	)
Depreciation, depletion and amortization		339		308		31			682		616		66
Other taxes		134		134		—			299		301		(2	)
Other income		56		57		(1	)		116		97		19
Interest and related charges		221		227		(6	)		444		464		(20	)
Income tax expense		190		63		127			489		249		240

An analysis of Dominion’s results of operations follows:

Second Quarter 2015 vs. 2014

Net revenue increased 11%, primarily reflecting:

• A $102 million increase from electric utility operations, primarily reflecting an increase from rate adjustment clauses ($74 million) and an increase in sales to retail customers, primarily due to an increase in cooling degree days ($31 million); and

• A $56 million increase in merchant generation margins, primarily due to a decrease in scheduled outage days at Millstone.

Other operations and maintenance decreased 24%, primarily reflecting:

• The absence of 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 $52 million decrease in planned outage costs primarily due to a decrease in scheduled outage days at Millstone.

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These decreases were partially offset by:

• A $45 million charge related to incremental future ash pond and landfill closure costs at certain utility generation facilities due to the enactment of the final CCR rule in April 2015;

• An $18 million increase in utility nuclear refueling outage costs primarily due to the amortization of outage costs that were previously deferred pursuant to Virginia legislation enacted in April 2014; and

• An $18 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income.

Depreciation, depletion and amortization increased 10%, primarily due to property additions.

Income tax expense increased $127 million, primarily reflecting higher pre-tax income.

Year-To-Date 2015 vs. 2014

Net revenue increased 18%, primarily reflecting:

• The absence of losses related to the repositioning of Dominion’s producer services business in the first quarter of 2014, reflecting the termination of natural gas trading and certain energy marketing activities ($317 million);

• The absence of losses related to the retail electric energy marketing business which was sold in the first quarter of 2014 ($133 million); and

• A $90 million increase from electric utility operations, primarily reflecting:

• An increase from rate adjustment clauses ($150 million);

• An increase in sales to retail customers, primarily due to an increase in cooling degree days ($35 million); and

• An increase in sales to customers due to the effect of changes in customer usage and other factors ($22 million); partially offset by

• An $85 million write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015; and

• A decrease in PJM ancillary revenues ($18 million).

Other operations and maintenance decreased 3%, primarily reflecting:

• The absence of 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 $71 million gain from agreements to convey Marcellus Shale development rights underneath several natural gas storage fields; and

• A $55 million decrease in planned outage costs primarily due to a decrease in scheduled outage days at Millstone.

These decreases were partially offset by:

• The absence of a gain on the sale of Dominion’s electric retail energy marketing business in March 2014 ($100 million), net of a $31 million write-off of goodwill;

• The absence of a gain on the sale of the Northern System ($59 million);

• A $50 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;

• A $45 million charge related to incremental future ash pond and landfill closure costs at certain utility generation facilities due to the enactment of the final CCR rule in April 2015;

• A $31 million increase in utility nuclear refueling outage costs primarily due to the amortization of outage costs that were previously deferred pursuant to Virginia legislation enacted in April 2014;

• A $29 million increase 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; and

• A $24 million increase primarily due to services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not impact net income.

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

Income tax expense increased 96%, primarily reflecting higher pre-tax income.

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Segment Results of Operations

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

	Net Income attributable to Dominion									Diluted EPS
	2015			2014			$ Change			2015			2014			$ Change
(millions, except EPS)
Second Quarter
DVP	$	117		$	116		$	1		$	0.20		$	0.20		$	—
Dominion Generation		250			159			91			0.42			0.27			0.15
Dominion Energy		129			130			(1	)		0.22			0.22			—
Primary operating segments		496			405			91			0.84			0.69			0.15
Corporate and Other		(83	)		(246	)		163			(0.14	)		(0.42	)		0.28
Consolidated	$	413		$	159		$	254		$	0.70		$	0.27		$	0.43
Year-To-Date
DVP	$	257		$	247		$	10		$	0.43		$	0.42		$	0.01
Dominion Generation		532			468			64			0.90			0.80			0.10
Dominion Energy		336			338			(2	)		0.57			0.58			(0.01	)
Primary operating segments		1,125			1,053			72			1.90			1.80			0.10
Corporate and Other		(176	)		(515	)		339			(0.30	)		(0.88	)		0.58
Consolidated	$	949		$	538		$	411		$	1.60		$	0.92		$	0.68

DVP

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

	Second Quarter							Year-To-Date
	2015		2014		% Change			2015		2014		% Change
Electricity delivered (million MWh)		20.1		19.3		4	%		43.0		41.7		3	%
Degree days (electric distribution service area):
Cooling		645		529		22			645		529		22
Heating		214		252		(15	)		2,578		2,546		1
Average electric distribution customer accounts (thousands)(1)		2,521		2,495		1			2,519		2,494		1

(1) Period average.

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

	Second Quarter 2015 vs. 2014 Increase (Decrease)						Year-To-Date 2015 vs. 2014 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	6		$	0.01		$	7		$	0.01
Other		1			—			7			0.01
FERC transmission equity return		8			0.01			20			0.03
Depreciation and amortization		(3	)		—			(5	)		(0.01	)
Other operations and maintenance expense		(9	)		(0.02	)		(14	)		(0.02	)
Other		(2	)		—			(5	)		(0.01	)
Change in net income contribution	$	1		$	—		$	10		$	0.01

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Dominion Generation

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

	Second Quarter							Year-To-Date
	2015		2014		% Change			2015		2014		% Change
Electricity supplied (million MWh):
Utility		20.4		19.4		5	%		43.3		41.9		3	%
Merchant		6.6		5.8		14			13.0		12.2		7
Degree days (electric utility service area):
Cooling		645		529		22			645		529		22
Heating		214		252		(15	)		2,578		2,546		1
Average retail energy marketing customer accounts (thousands)(1)(2)		1,288		1,245		3			1,269		1,340		(5	)

(1) Period average.

(2) 2014 excludes 511 thousand average retail electric energy marketing customer accounts due to the sale of this business in March 2014.

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

	Second Quarter 2015 vs. 2014 Increase (Decrease)						Year-To-Date 2015 vs. 2014 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Merchant generation margin	$	35		$	0.06		$	20		$	0.03
Regulated electric sales:
Weather		13			0.02			15			0.03
Other		—			—			9			0.02
PJM ancillary services		(2	)		—			(14	)		(0.02	)
Rate adjustment clause equity return		10			0.02			21			0.04
Depreciation and amortization		(6	)		(0.01	)		(12	)		(0.02	)
Outage costs		20			0.03			14			0.02
Renewable energy investment tax credits		30			0.05			31			0.05
Other		(9	)		(0.02	)		(20	)		(0.05	)
Change in net income contribution	$	91		$	0.15		$	64		$	0.10

Dominion Energy

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

	Second Quarter							Year-To-Date
	2015		2014		% Change			2015		2014		% Change
Gas distribution throughput (bcf):
Sales		3		4		(25	)%		19		21		(10	)%
Transportation		90		58		55			252		186		35
Heating degree days (gas distribution service area)		568		603		(6	)		4,143		4,116		1
Average gas distribution customer accounts (thousands)(1):
Sales		231		239		(3	)		239		243		(2	)
Transportation		1,069		1,059		1			1,065		1,058		1

(1) Period average.

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

	Second Quarter 2015 vs. 2014 Increase (Decrease)						Year-To-Date 2015 vs. 2014 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Blue Racer	$	(2	)	$	—		$	(37	)(1)	$	(0.06	)
Assignment of Marcellus acreage		(1	)		—			42			0.07
Noncontrolling interest(2)		(3	)		(0.01	)		(6	)		(0.01	)
Depreciation and amortization		(3	)		(0.01	)		(8	)		(0.02	)
Gas distribution margin:
Weather		—			—			1			—
Rate adjustment clauses		5			0.01			9			0.02
Other		4			0.01			5			0.01
Other		(1	)		—			(8	)		(0.02	)
Change in net income contribution	$	(1	)	$	—		$	(2	)	$	(0.01	)

(1) Primarily represents absence of a gain from the sale of the Northern System.

(2) Represents the portion of earnings attributable to Dominion Midstream’s public unitholders.

Corporate and Other

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

	Second Quarter									Year-To-Date
	2015			2014			$ Change			2015			2014			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	(17	)	$	(185	)	$	168		$	(62	)	$	(402	)	$	340
Specific items attributable to corporate operations		1			(17	)		18			(2	)		(28	)		26
Total specific items		(16	)		(202	)		186			(64	)		(430	)		366
Other corporate operations		(67	)		(44	)		(23	)		(112	)		(85	)		(27	)
Total net expense	$	(83	)	$	(246	)	$	163		$	(176	)	$	(515	)	$	339
EPS impact	$	(0.14	)	$	(0.42	)	$	0.28		$	(0.30	)	$	(0.88	)	$	0.58

Total Specific Items

Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing those segments’ performance or in allocating resources among the segments. See Note 20 to the Consolidated Financial Statements in this report for discussion of these items in more detail.

Virginia Power

Results of Operations

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

	Second Quarter						Year-To-Date
	2015		2014		$ Change		2015		2014		$ Change
(millions)
Net income	$	246	$	69	$	177	$	515	$	393	$	122

Overview

Second Quarter 2015 vs. 2014

Net income increased $177 million, primarily due to the absence of a 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.

Year-To-Date 2015 vs. 2014

Net income increased 31%, primarily due to the absence of a 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, partially offset by the write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015.

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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
	2015		2014		$ Change			2015		2014		$ Change
(millions)
Operating revenue	$	1,813	$	1,729	$	84		$	3,950	$	3,712	$	238
Electric fuel and other energy-related purchases		497		518		(21	)		1,307		1,168		139
Purchased electric capacity		90		87		3			184		175		9
Net revenue		1,226		1,124		102			2,459		2,369		90
Other operations and maintenance		445		633		(188	)		841		974		(133	)
Depreciation and amortization		231		217		14			469		435		34
Other taxes		69		69		—			143		142		1
Other income		21		21		—			36		36		—
Interest and related charges		108		103		5			216		210		6
Income tax expense		148		54		94			311		251		60

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

Second Quarter 2015 vs. 2014

Other operations and maintenance decreased 30%, primarily reflecting:

• The absence of 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.

This decrease was partially offset by:

• A $45 million charge related to incremental future ash pond and landfill closure costs at certain utility generation facilities due to the enactment of the final CCR rule in April 2015;

• An $18 million increase in utility nuclear refueling outage costs primarily due to the amortization of outage costs that were previously deferred pursuant to Virginia legislation enacted in April 2014; and

• An $18 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income.

Income tax expense increased $94 million, primarily reflecting higher pre-tax income.

Year-To-Date 2015 vs. 2014

Other operations and maintenance decreased 14%, primarily reflecting:

• The absence of 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.

This decrease was partially offset by:

• A $50 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;

• A $45 million charge related to incremental future ash pond and landfill closure costs at certain utility generation facilities due to the enactment of the final CCR rule in April 2015; and

• A $31 million increase in utility nuclear refueling outage costs primarily due to the amortization of outage costs that were previously deferred pursuant to Virginia legislation enacted in April 2014.

Income tax expense increased 24%, primarily reflecting higher pre-tax income.

Dominion Gas

Results of Operations

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

	Second Quarter							Year-To-Date
	2015		2014		$ Change			2015		2014		$ Change
(millions)
Net income	$	85	$	93	$	(8	)	$	246	$	257	$	(11	)

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Overview

Second Quarter 2015 vs. 2014

Net income decreased 9%, primarily reflecting higher interest expense.

Year-To-Date 2015 vs. 2014

Net income decreased 4%, primarily reflecting the absence of a gain on the sale of the Northern System and higher interest expense, partially offset by increased gains from agreements to convey Marcellus Shale development rights underneath several natural gas storage fields.

Analysis of Consolidated Operations

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

	Second Quarter							Year-To-Date
	2015		2014		$ Change			2015		2014		$ Change
(millions)
Operating revenue	$	395	$	428	$	(33	)	$	926	$	997	$	(71	)
Purchased gas		21		76		(55	)		95		213		(118	)
Other energy-related purchases		7		5		2			13		21		(8	)
Net revenue		367		347		20			818		763		55
Other operations and maintenance		124		109		15			198		162		36
Depreciation and amortization		53		49		4			104		96		8
Other taxes		37		35		2			92		86		6
Other income		4		5		(1	)		13		13		—
Interest and related charges		18		6		12			35		12		23
Income tax expense		54		60		(6	)		156		163		(7	)

An analysis of Dominion Gas’ results of operations follows:

Second Quarter 2015 vs. 2014

Other operations and maintenance increased 14%, primarily reflecting:

• A $14 million increase primarily due to services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not impact net income; and

• A $5 million increase 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.

Interest and related charges increased $12 million, primarily due to higher long-term debt interest expense resulting from debt issuances in December 2014.

Income tax expense decreased 10%, primarily reflecting lower pre-tax income.

Year-To-Date 2015 vs. 2014

Other operations and maintenance increased 22%, primarily reflecting:

• The absence of a gain on the sale of the Northern System ($59 million);

• A $29 million increase 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; and

• A $24 million increase primarily due to services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not impact net income; partially offset by

• A $71 million gain from agreements to convey Marcellus Shale development rights underneath several natural gas storage fields.

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Interest and related charges increased $23 million, primarily due to higher long-term debt interest expense resulting from debt issuances in December 2014.

Liquidity and Capital Resources

Dominion depends 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, 2015, Dominion had $1.8 billion of unused capacity under its credit facilities.

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

	2015			2014
(millions)
Cash and cash equivalents at January 1	$	318		$	316
Cash flows provided by (used in):
Operating activities		2,160			1,447
Investing activities		(3,084	)		(2,186	)
Financing activities		877			842
Net increase (decrease) in cash and cash equivalents		(47	)		103
Cash and cash equivalents at June 30	$	271		$	419

Operating Cash Flows

Net cash provided by Dominion’s operating activities increased by $713 million, primarily due to higher deferred fuel cost recoveries in its Virginia jurisdiction, higher revenue from rate adjustment clauses and the absence of losses related to the repositioning of Dominion’s producer services business in 2014.

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.

Dominion’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 the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.

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, 2015 for these activities. Gross credit exposure for each counterparty is calculated prior to the application of collateral and represents outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade(1)	$	208	$	88	$	120
Non-investment grade(2)		4		—		4
No external ratings:
Internally rated—investment grade(3)		14		—		14
Internally rated—non-investment grade(4)		50		—		50
Total	$	276	$	88	$	188

(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 58% of the total net credit exposure.

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

(3) The five largest counterparty exposures, combined, for this category represented approximately 7% of the total net credit exposure.

(4) The five largest counterparty exposures, combined, for this category represented approximately 19% of the total net credit exposure.

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Investing Cash Flows

Net cash used in Dominion’s investing activities increased by $898 million, primarily due to Dominion’s acquisition of DCGT in 2015, the absence of proceeds from the sale of Dominion’s electric retail energy marketing business and the sale of assets to Blue Racer in 2014 and higher acquisitions of solar development projects in 2015.

Financing Cash Flows and Liquidity

Dominion relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed further in Credit Ratings and Debt Covenants in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, 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 for certain issuances.

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

In 2015, net cash provided by Dominion’s financing activities increased by $35 million, primarily reflecting the issuance of common stock through an at-the-market program and the absence of subsidiary preferred stock redemptions, which were completed in 2014. These increases were partially offset by lower net debt issuances and higher dividend payments.

See Note 15 to the Consolidated Financial Statements in this report for further information regarding Dominion’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 the Credit Ratings section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, there is a discussion on the use of capital markets by Dominion as well as the impact of credit ratings on the accessibility and costs of using these markets. As of June 30, 2015, there have been no changes in Dominion’s credit ratings.

Debt Covenants

In the Debt Covenants section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, there is a discussion on the various covenants present in the enabling agreements underlying Dominion’s debt. As of June 30, 2015, there have been no material changes to debt covenants, nor any events of default under Dominion’s debt covenants.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of June 30, 2015, there have been no material changes outside the ordinary course of business to Dominion’s contractual obligations nor any material changes to planned capital expenditures as disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.

Use of Off-Balance Sheet Arrangements

As of June 30, 2015, there have been no material changes in the off-balance sheet arrangements disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.

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 Consolidated Financial Statements that may impact future results of operations, financial condition and/or cash flows. This section should be read in conjunction with Item 1. Business and Future Issues and Other Matters in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Future Issues and Other Matters in MD&A in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2015.

Environmental Matters

Dominion is 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 the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Note 16 to the Consolidated Financial Statements in this report for additional information on various environmental matters.

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In August 2015, the EPA announced the final rules for the Clean Power Plan. The Clean Power Plan uses 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 and expanding renewable resources. The new rule requires states to meet state-by-state emission rate or intensity-based CO2 binding goals or limits. States are required to submit interim plans to the EPA by summer 2016 identifying how they will comply with the rule, with final plans due by September 2018. Dominion’s most recent integrated resources plan filed in July 2015 includes four alternative plans that represent plausible compliance strategies with the rule as proposed, and which include additional coal unit retirements and additional low or zero-carbon resources. However, until the state plans are developed and the EPA approves the plans, Dominion cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.

Legal Matters

See Item 3. Legal Proceedings in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, Notes 12 and 15 to the Consolidated Financial Statements and Item 1. Legal Proceedings in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 and Notes 12 and 16 to the Consolidated Financial Statements and Item 1. Legal Proceedings in this report for additional information on various legal matters.

Regulatory Matters

See Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Note 12 in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 and in this report for additional information on various regulatory matters.

Greensville County

In July 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate Greensville County and related transmission interconnection facilities. The total estimated construction cost is approximately $1.3 billion (excluding financing costs). Virginia Power also applied for approval of Rider GV to recover the costs of Greensville County, and proposed a total revenue requirement of approximately $42 million for the rate year beginning April 1, 2016. This case is pending.

Electric Transmission Project

In May 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate in Loudoun County, Virginia, a new approximately 230 kV Poland Road Substation, and a new approximately four mile overhead 230 kV double circuit transmission line between the existing 230 kV Loudoun-Brambleton Line and the Poland Road Substation. The total estimated cost of the project is approximately $55 million. This case is pending.

Transco-to-Charleston Project

In 2014, DCGT executed binding precedent agreements with three customers for the Transco-to-Charleston project. The project is expected to cost approximately $120 million, and provide 80,000 Dths per day of firm transportation service from an existing interconnect with Transcontinental Gas Pipe Line Company, LLC in Spartanburg County, South Carolina to customers in Dillon, Marlboro, Sumter, Charleston, Lexington and Richland Counties, South Carolina. In July 2015, DCGT requested authorization to utilize the FERC pre-filing process. DCGT expects to file the application to request FERC authorization to construct and operate the project facilities in the first quarter of 2016. The project is expected to be placed into service in the fourth quarter of 2017.

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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’ natural 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 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 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 commodity-based financial derivative instruments would have resulted in an increase in fair value of approximately $67 million and $101 million as of June 30, 2015 and December 31, 2014, respectively. The decline in sensitivity is largely due to decreased commodity derivative activity and lower commodity prices.

A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of Virginia Power’s commodity-based financial derivatives as of June 30, 2015 or December 31, 2014.

A hypothetical 10% unfavorable change in commodity prices of Dominion Gas’ commodity-based financial derivative instruments would have resulted in an increase in fair value of approximately $8 million and $2 million as of June 30, 2015 and December 31, 2014, respectively. The rise in sensitivity is largely due to increased commodity derivative activity.

The impact of a change in energy commodity prices on the Companies’ 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, 2015 or December 31, 2014.

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

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As of June 30, 2015 Dominion, Virginia Power and Dominion Gas had $3.8 billion, $1.2 billion and $250 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 $46 million, $30 million and $2 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at June 30, 2015. As of December 31, 2014, Dominion, Virginia Power and Dominion Gas had $4.1 billion, $1.5 billion and $250 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 $46 million, $25 million and $2 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2014.

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 Dominion’s and Virginia Power’s Consolidated Balance Sheets at fair value.

Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $102 million, $71 million and $176 million for the six months ended June 30, 2015 and 2014 and for the year ended December 31, 2014, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on these investments of $62 million for the six months ended June 30, 2015, and a net increase in unrealized gains on these investments of $127 million and $172 million for the six months ended June 30, 2014 and for the year ended December 31, 2014, respectively.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $38 million, $32 million and $77 million for the six months ended June 30, 2015 and 2014 and for the year ended December 31, 2014, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on these investments of $21 million for the six months ended June 30, 2015, and a net increase in unrealized gains on these investments of $61 million and $87 million for the six months ended June 30, 2014 and for the year ended December 31, 2014, 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 net 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 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.

In March 2015, DTI received a draft compliance order from the WVDEP in connection with a permit determination relating to emission sources at the Galmish loading and storage facility. The draft compliance order included a proposed penalty of $162,000. In June 2015, DTI and WVDEP finalized a consent order resolving this matter, which included a final penalty of $84,000.

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

• Notes 13 and 22 to the Consolidated Financial Statements and Future Issues and Other Matters in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, which information is incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which the Companies are a party.

• Notes 12 and 15 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2015.

• Notes 12 and 16 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 the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, which should be taken into consideration when reviewing the information contained in this report. There have been no material changes with regard to the risk factors previously disclosed in the Companies’ Annual Report on Form 10-K for the year ended December 31, 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, see Forward-Looking Statements in MD&A.

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

Dominion

ISSUER PURCHASES OF EQUITY SECURITIES

Period	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)
4/1/15-4/30/15		241	$	71.51		—	19,629,059 shares/ $1.18 billion
5/1/15-5/31/15		—		—		—	19,629,059 shares/ $1.18 billion
6/1/15-6/30/15		—		—		—	19,629,059 shares/ $1.18 billion
Total		241	$	71.51		—	19,629,059 shares/ $1.18 billion

(1) In April 2015, 241 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.

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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 October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 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 6, 2015 (Exhibit 3.1, Form 8-K filed May 6, 2015, 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	Indenture, dated as of June 1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489); First Supplemental Indenture, dated as of June 1, 2015 (Exhibit 4.2, Form 8-K filed June 15, 2015, File No. 1-8489).	X
4.2	Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of Tenth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Twelfth Supplemental Indenture, dated January 1, 2006 (Exhibit 4.2, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Thirteenth Supplemental Indenture, dated as of January 1, 2006 (Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Form of Seventeenth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Ninth Supplemental Indenture, dated May 1, 2015 (Exhibit 4.3, Form 8-K filed May 13, 2015, File No. 1-02255); Thirtieth Supplemental Indenture, dated May 1, 2015 (Exhibit 4.4, Form 8-K filed May 13, 2015, File No. 1-02255).		X

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12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X
12.2	Ratio of earnings to fixed charges 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	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, 2015, filed on August 6, 2015, 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

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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
August 6, 2015	/s/    Michele L. Cardiff
	Michele L. Cardiff Vice President, Controller and Chief Accounting Officer
	VIRGINIA ELECTRIC AND POWER COMPANY Registrant
August 6, 2015	/s/    Michele L. Cardiff
	Michele L. Cardiff Vice President, Controller and Chief Accounting Officer
	DOMINION GAS HOLDINGS, LLC Registrant
August 6, 2015	/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 October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 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 6, 2015 (Exhibit 3.1, Form 8-K filed May 6, 2015, 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	Indenture, dated as of June 1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489); First Supplemental Indenture, dated as of June 1, 2015 (Exhibit 4.2, Form 8-K filed June 15, 2015, File No. 1-8489).	X
4.2	Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of Tenth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Twelfth Supplemental Indenture, dated January 1, 2006 (Exhibit 4.2, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Thirteenth Supplemental Indenture, dated as of January 1, 2006 (Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Form of Seventeenth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255); Twenty-Second Supplemental Indenture, dated as of January 1, 2012 (Exhibit 4.3, Form 8-K filed January 12, 2012, File No. 1-2255); Twenty-Third Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.3, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fourth Supplemental Indenture, dated as of January 1, 2013 (Exhibit 4.4, Form 8-K filed January 8, 2013, File No. 1-2255); Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255); Twenty-Sixth Supplemental Indenture, dated as of August 1, 2013 (Exhibit 4.3, Form 8-K filed August 15, 2013, File No. 1-2255); Twenty-Seventh Supplemental Indenture, dated February 1, 2014 (Exhibit 4.3, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Eighth Supplemental Indenture, dated February 1, 2014 (Exhibit 4.4, Form 8-K filed February 7, 2014, File No. 1-2255); Twenty-Ninth Supplemental Indenture, dated May 1, 2015 (Exhibit 4.3, Form 8-K filed May 13, 2015, File No. 1-02255); Thirtieth Supplemental Indenture, dated May 1, 2015 (Exhibit 4.4, Form 8-K filed May 13, 2015, File No. 1-02255).		X

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12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X
12.2	Ratio of earnings to fixed charges 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	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, 2015, filed on August 6, 2015, 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

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