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

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

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

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

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

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

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

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

At ~~July~~October 15, 2016, the latest practicable date for determination, Dominion Resources, Inc. had ~~625,763,030~~626,750,459 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.

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


Abbreviation or Acronym		Definition

Dominion Questar Combination		Agreement and plan of merger entered on January 31, 2016 between Dominion and Dominion Questar in which Dominion Questar became a wholly-owned subsidiary of Dominion upon closing on September 16, 2016

DRS		Dominion Resources Services, Inc.

DSM		Demand-side management

Dth		Dekatherm

DTI		Dominion Transmission, Inc.

Duke		The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries, or operating segments, or the entirety of Duke Energy Corporation and its consolidated subsidiaries

DVP		Dominion Virginia Power operating segment

East Ohio		The East Ohio Gas Company, doing business as Dominion East Ohio

EPA		Environmental Protection Agency

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~~NRG effective November 2016

Fowler Ridge		A wind-turbine facility joint venture between Dominion and BP Wind Energy North America Inc. in Benton County, Indiana

FTA		Free Trade Agreement

FTRs		Financial transmission rights

GAAP		United States generally accepted accounting principles

Gal		Gallon

GHG		Greenhouse gas

Granite Mountain		Granite Mountain Holdings, LLC, a limited liability company owned by Dominion and Granite Mountain Renewables, LLC, a wholly-owned subsidiary of ~~SunEdison~~NRG effective November 2016

Greensville County		An approximately 1,588 MW proposed natural gas-fired combined-cycle power station ~~under construction~~ 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

Hope		Hope Gas, Inc., doing business as Dominion Hope

Iron Springs		Iron Springs Holdings, LLC, a limited liability company owned by Dominion and Iron Springs Renewables, LLC, a wholly-owned subsidiary of ~~SunEdison~~NRG effective November 2016

Iroquois		Iroquois Gas Transmission System, L.P.

ISO-NE		Independent System Operator New England

July 2016 hybrids		2016 Series A Enhanced Junior Subordinated Notes due 2076

June 2006 hybrids		2006 Series A Enhanced Junior Subordinated Notes due 2066

kV		Kilovolt

Liquefaction Project		A natural gas export/liquefaction facility currently under construction by Cove Point

LNG		Liquefied natural gas

Local 50		International Brotherhood of Electrical Workers Local 50

Local 69		Local 69, Utility Workers Union of America, United Gas Workers

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

MISO		Midcontinent Independent Transmission System Operator, Inc.

MW		Megawatt

MWh		Megawatt hour

NedPower		A wind-turbine facility joint venture between Dominion and Shell Wind Energy, Inc. in Grant County, West Virginia

NGLs		Natural gas liquids

NO_x		Nitrogen oxide

North Carolina Commission		North Carolina Utilities Commission

NRC		Nuclear Regulatory Commission


Abbreviation or Acronym		Definition

NRG		The legal entity, NRG Energy, Inc., one or more of its consolidated subsidiaries (including, effective November 2016, Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of NRG Energy, Inc. and its consolidated subsidiaries

NSPS		New Source Performance Standards

NYSE		New York Stock Exchange

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

PIR		Pipeline Infrastructure Replacement program deployed by East Ohio

PJM		PJM Interconnection, L.L.C.

ppb		Parts-per-billion

PREP		Pipeline Replacement and Expansion Program, a program of replacing, upgrading and expanding natural gas utility infrastructure ~~to be~~ deployed by Hope

PSD		Prevention of Significant Deterioration


~~Abbreviation or Acronym~~ PSMP		~~Definition~~ Pipeline Safety Management Program deployed by East Ohio

Questar Gas		~~The legal entity,~~ Questar ~~Corporation,~~Gas Company

Questar Pipeline		Questar Pipeline, LLC (successor by statutory conversion to and formerly known as Questar Pipeline Company), one or more of its consolidated subsidiaries, or ~~operating segments, or~~ the entirety of Questar ~~Corporation~~Pipeline, LLC and its consolidated subsidiaries

~~Questar Combination~~		~~Agreement and plan of merger entered on January 31, 2016 between Dominion and Questar in which Questar will become a wholly-owned subsidiary of Dominion upon closing~~

REIT		Real estate investment trust

~~Rider B~~		~~A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Power’s coal-fired power stations to biomass~~

Rider BW		A rate adjustment clause associated with the recovery of costs related to Brunswick County

Rider GVU		A rate adjustment clause associated with the recovery of ~~costs related to Greensville County~~

~~Rider R~~		~~A rate adjustment clause associated with the recovery of costs related to Bear Garden~~

~~Rider S~~		~~A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center~~

~~Rider T1~~		~~A rate adjustment clause to recover the difference between revenues produced from transmission rates included in base rates, and the~~ new ~~total revenue requirement developed annually for the rate years effective September 1~~underground distribution facilities

Rider US-2		A rate adjustment clause associated with the recovery of costs related to Woodland, Scott Solar and Whitehouse

~~Rider W~~Riders C1A and C2A		~~A rate~~Rate adjustment ~~clause~~clauses associated with the recovery of costs related to ~~Warren County~~certain DSM programs approved in DSM cases

ROE		Return on equity

RSN		Remarketable subordinated note

Scott Solar		An approximately 17 MW ~~proposed~~ utility-scale solar power station under construction in Powhatan County, Virginia

SEC		Securities and Exchange Commission

September 2006 hybrids		2006 Series B Enhanced Junior Subordinated Notes due 2066

SO₂		Sulfur dioxide

Standard & Poor’s		Standard & Poor’s Ratings Services, a division of McGraw Hill Financial, Inc.

SunEdison		The legal entity, SunEdison, Inc., one or more of its consolidated subsidiaries (including, through November 2016, Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of SunEdison, Inc. and its consolidated subsidiaries

Terra Nova Renewable Partners		A partnership between SunEdison and institutional investors advised by J.P. Morgan Asset Management-Global Real Assets

Three Cedars		Granite Mountain and Iron Springs, collectively

TransCanada		The legal entity, TransCanada Corporation, one or more of its consolidated subsidiaries, or operating segments, or the entirety of TransCanada Corporation and its consolidated subsidiaries

UAO		Unilateral Administrative Order

~~UEX Rider~~Utah Commission		~~Uncollectible Expense Rider deployed by East Ohio~~Public Service Commission of Utah

VDEQ		Virginia Department of Environmental Quality

VEBA		Voluntary Employees’ Beneficiary Association

VIE		Variable interest entity

~~Virginia City Hybrid Energy Center~~		~~A 610 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

VOC		Volatile organic compounds

~~Warren County~~West Virginia Commission		~~A 1,342 MW combined-cycle,~~Public Service Commission of West Virginia

White River Hub		White River Hub, LLC, a FERC-regulated transporter of natural ~~gas-fired power station~~gas in ~~Warren County, Virginia~~western Colorado

Whitehouse		An approximately 20 MW ~~proposed~~ utility-scale solar power station under construction in Louisa County, Virginia

Woodland		An approximately 19 MW ~~proposed~~ utility-scale solar power station under construction in Isle of Wight County, Virginia

Wyoming Commission		Wyoming Public Service Commission


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015		2016		2015		2016			2015		2016		2015
(millions, except per share amounts)
Operating Revenue	$	2,598	$	2,747	$	5,519	$	6,156	$	3,132		$	2,971	$	8,651	$	9,127

Operating Expenses
Electric fuel and other energy-related purchases		551		591		1,185		1,544		606			636		1,791		2,180
Purchased electric capacity		45		90		113		184
Purchased (excess) electric capacity										(6	)		75		107		259
Purchased gas		56		111		175		361		77			85		252		446
Other operations and maintenance		665		709		1,368		1,311		765			564		2,133		1,875
Depreciation, depletion and amortization		361		339		712		682		400			355		1,112		1,037
Other taxes		139		134		303		299		145			133		448		432

Total operating expenses		1,817		1,974		3,856		4,381		1,987			1,848		5,843		6,229

Income from operations		781		773		1,663		1,775		1,145			1,123		2,808		2,898

Other income		72		56		126		116		63			11		189		127
Interest and related charges		239		221		465		444		250			230		715		674

Income from operations including noncontrolling interests before income tax expense		614		608		1,324		1,447		958			904		2,282		2,351
Income tax expense		152		190		331		489		230			305		561		794

Net Income Including Noncontrolling Interests		462		418		993		958		728			599		1,721		1,557
Noncontrolling Interests		10		5		17		9		38			6		55		15

Net Income Attributable to Dominion	$	452	$	413	$	976	$	949	$	690		$	593	$	1,666	$	1,542

Earnings Per Common Share
Net income attributable to Dominion - Basic	$	0.73	$	0.70	$	1.61	$	1.61	$	1.10		$	1.00	$	2.72	$	2.61
Net income attributable to Dominion - Diluted		0.73		0.70		1.61		1.60		1.10			1.00		2.71		2.60

Dividends Declared Per Common Share	$	0.7000	$	0.6475	$	1.4000	$	1.2950	$	0.7000		$	0.6475	$	2.1000	$	1.9425

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015			2016			2015			2016			2015
(millions)
Net income including noncontrolling interests	$	462		$	418		$	993		$	958		$	728		$	599		$	1,721		$	1,557
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities⁽¹⁾		(11	)		92			42			34			14			(7	)		56			25
Changes in unrealized net gains (losses) on investment securities⁽²⁾		26			(11	)		41			4			31			(59	)		72			(55	)
Changes in unrecognized pension and other postretirement benefit costs⁽³⁾		—			3			—			3			15			(9	)		15			(6	)
Amounts reclassified to net income:
Net derivative gains-hedging activities⁽⁴⁾		(44	)		(61	)		(107	)		(2	)		(34	)		(53	)		(141	)		(53	)
Net realized gains on investment securities⁽⁵⁾		(8	)		(12	)		(10	)		(33	)		(13	)		(2	)		(23	)		(35	)
Net pension and other postretirement benefit costs⁽⁶⁾		8			12			16			25			9			14			25			39
Changes in other comprehensive loss from equity method investees⁽⁷⁾		(1	)		—			(1	)		(1	)
Changes in other comprehensive income (loss) from equity method investees⁽⁷⁾														—			1			(1	)		—

Total other comprehensive income (loss)		(30	)		23			(19	)		30			22			(115	)		3			(85	)

Comprehensive income including noncontrolling interests		432			441			974			988			750			484			1,724			1,472
Comprehensive income attributable to noncontrolling interests		10			5			17			9			38			6			55			15

Comprehensive income attributable to Dominion	$	422		$	436		$	957		$	979		$	712		$	478		$	1,669		$	1,457

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


	June 30, 2016			December 31, 2015⁽¹⁾			September 30, 2016			December 31, 2015⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	377		$	607		$	251		$	607
Restricted cash and cash equivalents		516			17
Customer receivables (less allowance for doubtful accounts of $19 and $32)		1,140			1,200
Customer receivables (less allowance for doubtful accounts of $18 and $32)								1,259			1,200
Other receivables (less allowance for doubtful accounts of $3 and $2)		139			169			133			169
Inventories		1,351			1,348			1,516			1,348
Prepayments		143			198			147			198
Other		477			650			493			667

Total current assets		4,143			4,189			3,799			4,189

Investments
Nuclear decommissioning trust funds		4,331			4,183			4,427			4,183
Investment in equity method affiliates		1,372			1,320			1,498			1,320
Other		277			271			299			271

Total investments		5,980			5,774			6,224			5,774

Property, Plant and Equipment
Property, plant and equipment		60,490			57,776			68,282			57,776
Accumulated depreciation, depletion and amortization		(16,808	)		(16,222	)		(19,394	)		(16,222	)

Total property, plant and equipment, net		43,682			41,554			48,888			41,554

Deferred Charges and Other Assets
Goodwill		3,294			3,294			6,405			3,294
Pension and other postretirement benefit assets		1,017			943			1,095			943
Regulatory assets		2,150			1,865			2,143			1,865
Other		1,103			1,029			1,045			1,029

Total deferred charges and other assets		7,564			7,131			10,688			7,131

Total assets	$	61,369		$	58,648		$	69,599		$	58,648

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


	June 30, 2016			December 31, 2015⁽¹⁾			September 30, 2016			December 31, 2015⁽¹⁾
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	1,348		$	1,825		$	2,931		$	1,825
Short-term debt		3,437			3,509			3,097			3,509
Accounts payable		589			726			685			726
Accrued interest, payroll and taxes		561			515			800			515
Other⁽²⁾		1,331			1,544			1,514			1,544

Total current liabilities		7,266			8,119			9,027			8,119

Long-Term Debt
Long-term debt		21,406			20,048			23,356			20,048
Junior subordinated notes		2,399			1,340			2,980			1,340
Remarketable subordinated notes		982			2,080			2,371			2,080

Total long-term debt		24,787			23,468			28,707			23,468

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		7,666			7,414			8,675			7,414
Asset retirement obligations		1,941			1,887			2,153			1,887
Regulatory liabilities		2,318			2,285			2,597			2,285
Other		1,939			1,873			2,248			1,873

Total deferred credits and other liabilities		13,864			13,459			15,673			13,459

Total liabilities		45,917			45,046			53,407			45,046

Commitments and Contingencies (see Note 15)
Equity
Common stock – no par⁽³⁾		8,160			6,680			8,592			6,680
Retained earnings		6,585			6,458			6,837			6,458
Accumulated other comprehensive loss		(493	)		(474	)		(471	)		(474	)

Total common shareholders’ equity		14,252			12,664			14,958			12,664

Noncontrolling interests		1,200			938			1,234			938

Total equity		15,452			13,602			16,192			13,602

Total liabilities and equity	$	61,369		$	58,648		$	69,599		$	58,648

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


	Common Stock					Dominion Shareholders															Common Stock					Dominion Shareholders
	Shares		Amount			Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Shareholders’ Equity			Noncontrolling Interests			Total Equity			Shares		Amount			Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Shareholders’ Equity			Noncontrolling Interests			Total Equity
(millions)
December 31, 2015		596	$	6,680		$	6,458		$	(474	)	$	12,664		$	938		$	13,602			596	$	6,680		$	6,458		$	(474	)	$	12,664		$	938		$	13,602

Net income including noncontrolling interests							976						976			17			993								1,666						1,666			55			1,721
Contributions from SunEdison to Four Brothers and Three Cedars													—			162			162														—			178			178
Sale of interest in merchant solar projects				22									22			117			139					22									22			117			139
Purchase of Dominion Midstream common units				(2	)								(2	)		(11	)		(13	)				(3	)								(3	)		(14	)		(17	)
Issuance of common stock		21		1,458									1,458						1,458			31		2,079									2,079						2,079
Stock awards (net of change in unearned compensation)				6									6						6					10									10						10
Present value of stock purchase contract payments related to RSNs																								(191	)								(191	)					(191	)
Dividends and distributions							(849	)					(849	)		(23	)		(872	)							(1,287	)					(1,287	)		(39	)		(1,326	)
Other comprehensive loss, net of tax										(19	)		(19	)					(19	)
Other comprehensive income, net of tax																														3			3						3
Other				(4	)								(4	)					(4	)				(5	)								(5	)		(1	)		(6	)

June 30, 2016		617	$	8,160		$	6,585		$	(493	)	$	14,252		$	1,200		$	15,452
September 30, 2016																						627	$	8,592		$	6,837		$	(471	)	$	14,958		$	1,234		$	16,192

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


Six Months Ended June 30,	2016			2015
Nine Months Ended September 30,							2016			2015
(millions)
Operating Activities
Net income including noncontrolling interests	$	993		$	958		$	1,721		$	1,557
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)		853			822			1,325			1,250
Deferred income taxes and investment tax credits		275			399			481			703
Gains on the sales of assets and equity method investment in Iroquois		(45	)		(71	)		(50	)		(123	)
Other adjustments		(27	)		(18	)		(78	)		(1	)
Changes in:
Accounts receivable		82			214			19			229
Inventories		(3	)		47			(10	)		(3	)
Deferred fuel and purchased gas costs, net		114			28			84			70
Prepayments		55			47			71			45
Accounts payable		(92	)		(173	)		(89	)		(222	)
Accrued interest, payroll and taxes		46			(41	)		205			(13	)
Margin deposit assets and liabilities		(13	)		186			1			205
Other operating assets and liabilities		(220	)		(238	)		(294	)		(244	)

Net cash provided by operating activities		2,018			2,160			3,386			3,453

Investing Activities
Plant construction and other property additions (including nuclear fuel)		(3,160	)		(2,370	)		(4,536	)		(3,632	)
Acquisition of Dominion Questar, net of cash acquired								(4,372	)		—
Acquisition of solar development projects		—			(230	)		(21	)		(278	)
Acquisition of DCG		—			(497	)		—			(497	)
Proceeds from sales of securities		709	��		580			1,009			937
Purchases of securities		(752	)		(553	)		(1,065	)		(921	)
Restricted cash and cash equivalents		(500	)		—
Proceeds from assignments of shale development rights		5			28			10			80
Other		(27	)		(42	)		(54	)		(39	)

Net cash used in investing activities		(3,725	)		(3,084	)		(9,029	)		(4,350	)

Financing Activities
Repayment of short-term debt, net		(72	)		(153	)		(713	)		(220	)
Issuance of short-term notes								1,200			—
Repayment and repurchase of short-term notes		(600	)		—			(600	)		—
Issuance of long-term debt		1,930			1,200
Issuance and remarketing of long-term debt								5,730			2,262
Repayment and repurchase of long-term debt		(500	)		(8	)		(1,169	)		(675	)
Proceeds from sale of interest in merchant solar projects		117			—			117			—
Contributions from SunEdison to Four Brothers and Three Cedars		162			—			178			—
Issuance of common stock		1,458			647			2,079			717
Common dividend payments		(849	)		(765	)		(1,287	)		(1,150	)
Other		(169	)		(44	)		(248	)		(117	)

Net cash provided by financing activities		1,477			877			5,287			817

Decrease in cash and cash equivalents		(230	)		(47	)		(356	)		(80	)
Cash and cash equivalents at beginning of period		607			318			607			318

Cash and cash equivalents at end of period	$	377		$	271		$	251		$	238

Supplemental Cash Flow Information
Significant noncash investing and financing activities⁽¹⁾:
Significant noncash investing and financing activities⁽¹⁾⁽²⁾:
Accrued capital expenditures	$	257		$	319		$	341		$	389
Dominion Midstream’s acquisition of a noncontrolling partnership interest in Iroquois in exchange for issuance of Dominion Midstream common units								—			216

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015		2016		2015		2016			2015		2016		2015
(millions)
Operating Revenue⁽¹⁾	$	1,776	$	1,813	$	3,666	$	3,950	$	2,211		$	2,058	$	5,877	$	6,008

Operating Expenses
Electric fuel and other energy-related purchases⁽¹⁾		475		497		1,011		1,307		516			554		1,527		1,861
Purchased electric capacity		45		90		113		184
Purchased (excess) electric capacity										(6	)		75		107		259
Other operations and maintenance:
Affiliated suppliers		64		69		165		144		73			64		238		208
Other		322		376		671		697		370			311		1,041		1,008
Depreciation and amortization		247		231		495		469		270			244		765		713
Other taxes		70		69		144		143		74			69		218		212

Total operating expenses		1,223		1,332		2,599		2,944		1,297			1,317		3,896		4,261

Income from operations		553		481		1,067		1,006		914			741		1,981		1,747

Other income		18		21		34		36		13			13		47		49
Interest and related charges		113		108		227		216		118			116		345		332

Income before income tax expense		458		394		874		826		809			638		1,683		1,464
Income tax expense		178		148		331		311		306			253		637		564

Net Income	$	280	$	246	$	543	$	515	$	503		$	385	$	1,046	$	900

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015			2016			2015			2016			2015
(millions)
Net income	$	280		$	246		$	543		$	515		$	503		$	385		$	1,046		$	900
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities⁽¹⁾		(6	)		7			(15	)		3
Changes in unrealized net gains on nuclear decommissioning trust funds⁽²⁾		3			—			6			1
Net deferred losses on derivatives-hedging activities⁽¹⁾														(1	)		(6	)		(16	)		(3	)
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds⁽²⁾														4			(11	)		10			(10	)
Amounts reclassified to net income:
Net derivative losses-hedging activities⁽³⁾		—			—			—			1			—			—			—			1
Net realized gains on nuclear decommissioning trust funds⁽⁴⁾		(1	)		(2	)		(1	)		(3	)		(1	)		(1	)		(2	)		(4	)

Total other comprehensive income (loss)		(4	)		5			(10	)		2			2			(18	)		(8	)		(16	)

Comprehensive income	$	276		$	251		$	533		$	517		$	505		$	367		$	1,038		$	884

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


	June 30, 2016			December 31, 2015⁽¹⁾			September 30, 2016			December 31, 2015⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	61		$	18		$	18		$	18
Customer receivables (less allowance for doubtful accounts of $13 and $27)		837			822
Customer receivables (less allowance for doubtful accounts of $10 and $27)								937			822
Other receivables (less allowance for doubtful accounts of $1 at both dates)		79			109			87			109
Affiliated receivables		2			296			1			296
Inventories (average cost method)		860			873			836			873
Prepayments		73			38			23			38
Regulatory assets		193			326			197			326
Other⁽²⁾		39			22			33			22

Total current assets		2,144			2,504			2,132			2,504

Investments
Nuclear decommissioning trust funds		2,030			1,945			2,074			1,945
Other		4			3			3			3

Total investments		2,034			1,948			2,077			1,948

Property, Plant and Equipment
Property, plant and equipment		38,734			37,639			39,428			37,639
Accumulated depreciation and amortization		(12,076	)		(11,708	)		(12,314	)		(11,708	)

Total property, plant and equipment, net		26,658			25,931			27,114			25,931

Deferred Charges and Other Assets
Regulatory assets		966			667			897			667
Other⁽²⁾		591			515			527			515

Total deferred charges and other assets		1,557			1,182			1,424			1,182

Total assets	$	32,393		$	31,565		$	32,747		$	31,565

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


	June 30, 2016		December 31, 2015⁽¹⁾		September 30, 2016		December 31, 2015⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	99	$	476	$	679	$	476
Short-term debt		1,423		1,656		965		1,656
Accounts payable		311		366		330		366
Payables to affiliates		74		73		84		73
Affiliated current borrowings		—		376		—		376
Accrued interest, payroll and taxes		229		190		321		190
Regulatory liabilities		112		35		75		35
Other⁽²⁾		585		558		690		558

Total current liabilities		2,833		3,730		3,144		3,730

Long-Term Debt		9,562		8,892		8,963		8,892

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		4,885		4,654		5,017		4,654
Asset retirement obligations		1,154		1,104		1,194		1,104
Regulatory liabilities		1,956		1,929		1,967		1,929
Other⁽²⁾		829		615		784		615

Total deferred credits and other liabilities		8,824		8,302		8,962		8,302

Total liabilities		21,219		20,924		21,069		20,924

Commitments and Contingencies (see Note 15)
Common Shareholder’s Equity
Common stock – no par⁽³⁾		5,738		5,738		5,738		5,738
Other paid-in capital		1,113		1,113		1,113		1,113
Retained earnings		4,293		3,750		4,795		3,750
Accumulated other comprehensive income		30		40		32		40

Total common shareholder’s equity		11,174		10,641		11,678		10,641

Total liabilities and shareholder’s equity	$	32,393	$	31,565	$	32,747	$	31,565

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


Six Months Ended June 30,	2016			2015
Nine Months Ended September 30,							2016			2015
(millions)
Operating Activities
Net income	$	543		$	515		$	1,046		$	900
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		589			555			903			844
Deferred income taxes and investment tax credits		228			13			369			9
Other adjustments		(11	)		(6	)		(15	)		20
Changes in:
Accounts receivable		7			40			(99	)		10
Affiliated receivables and payables		295			1			306			(33	)
Inventories		13			25			37			11
Prepayments		(35	)		229			15			228
Deferred fuel expenses, net		105			(9	)		79			40
Accounts payable		(10	)		(9	)		4			(62	)
Accrued interest, payroll and taxes		39			38			131			137
Other operating assets and liabilities		(61	)		2			8			70

Net cash provided by operating activities		1,702			1,394			2,784			2,174

Investing Activities
Plant construction and other property additions		(1,226	)		(1,292	)		(1,835	)		(1,840	)
Purchases of nuclear fuel		(78	)		(67	)		(106	)		(100	)
Proceeds from sales of securities		347			209			478			407
Purchases of securities		(373	)		(222	)		(513	)		(423	)
Other		(6	)		(27	)		(11	)		(38	)

Net cash used in investing activities		(1,336	)		(1,399	)		(1,987	)		(1,994	)

Financing Activities
Issuance (repayment) of short-term debt, net		(233	)		80			(691	)		1
Repayment of affiliated current borrowings, net		(376	)		(427	)		(376	)		(427	)
Issuance of long-term debt		750			700
Issuance and remarketing of long-term debt								750			1,112
Repayment of long-term debt		(457	)		(6	)		(476	)		(421	)
Common dividend payments to parent		—			(270	)		—			(416	)
Other		(7	)		(5	)		(4	)		(5	)

Net cash provided by (used in) financing activities		(323	)		72
Net cash used in financing activities								(797	)		(156	)

Increase in cash and cash equivalents		43			67			—			24
Cash and cash equivalents at beginning of period		18			15			18			15

Cash and cash equivalents at end of period	$	61		$	82		$	18		$	39

Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	142		$	117		$	209		$	139

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015		2016		2015		2016		2015
(millions)
Operating Revenue⁽¹⁾	$	368	$	395	$	799	$	926	$	382	$	365	$	1,181	$	1,291

Operating Expenses
Purchased gas⁽¹⁾		16		21		50		95		21		8		71		103
Other energy-related purchases		1		7		4		13		4		4		8		17
Other operations and maintenance:
Affiliated suppliers		16		17		43		38		20		12		63		50
Other		58		107		155		160		113		51		268		211
Depreciation and amortization		52		53		95		104		55		53		150		157
Other taxes		39		37		91		92		36		35		127		127

Total operating expenses		182		242		438		502		249		163		687		665

Income from operations		186		153		361		424		133		202		494		626

Other income		9		4		15		13		7		4		22		17
Interest and related charges		23		18		45		35		23		18		68		53

Income from operations before income taxes		172		139		331		402		117		188		448		590
Income tax expense		67		54		128		156		34		77		162		233

Net Income	$	105	$	85	$	203	$	246	$	83	$	111	$	286	$	357

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015			2016			2015			2016			2015
(millions)
Net income	$	105		$	85		$	203		$	246		$	83		$	111		$	286		$	357
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities⁽¹⁾		(9	)		3			(15	)		(1	)		9			3			(6	)		2
Amounts reclassified to net income:
Net derivative gains-hedging activities⁽²⁾		—			(1	)		(2	)		(1	)		(1	)		(2	)		(3	)		(3	)
Net pension and other postretirement benefit costs⁽³⁾		1			1			1			2			1			1			2			3

Total other comprehensive income (loss)		(8	)		3			(16	)		—			9			2			(7	)		2

Comprehensive income	$	97		$	88		$	187		$	246		$	92		$	113		$	279		$	359

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


	June 30, 2016			December 31, 2015⁽¹⁾			September 30, 2016			December 31, 2015⁽¹⁾
(millions)
ASSETS
ASSETS
Current Assets
Cash and cash equivalents	$	226		$	13		$	8		$	13
Customer receivables (less allowance for doubtful accounts of $1 at both dates)⁽²⁾		176			219			158			219
Other receivables (less allowance for doubtful accounts of $2 at both dates)⁽²⁾		11			7
Other receivables (less allowance for doubtful accounts of $1 and $2)⁽²⁾								12			7
Affiliated receivables		6			98			5			98
Inventories		90			78			94			78
Prepayments		59			88			73			88
Other⁽²⁾		56			63			55			63

Total current assets		624			566			405			566

Investments		99			104			98			104

Property, Plant and Equipment
Property, plant and equipment		10,053			9,693			10,259			9,693
Accumulated depreciation and amortization		(2,766	)		(2,690	)		(2,808	)		(2,690	)

Total property, plant and equipment, net		7,287			7,003			7,451			7,003

Deferred Charges and Other Assets
Goodwill		542			542			542			542
Pension and other postretirement benefit assets⁽²⁾		1,579			1,510			1,613			1,510
Other⁽²⁾		604			583			634			583

Total deferred charges and other assets		2,725			2,635			2,789			2,635

Total assets	$	10,735		$	10,308		$	10,743		$	10,308

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


	June 30, 2016			December 31, 2015⁽¹⁾			September 30, 2016			December 31, 2015⁽¹⁾
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	400		$	400		$	400		$	400
Short-term debt		238			391			60			391
Accounts payable		124			201			124			201
Payables to affiliates		17			22			20			22
Affiliated current borrowings		—			95			—			95
Accrued interest, payroll and taxes		155			183			176			183
Other⁽²⁾		161			183			162			183

Total current liabilities		1,095			1,475			942			1,475

Long-Term Debt		3,541			2,869			3,545			2,869

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,331			2,214			2,414			2,214
Other⁽²⁾		412			432			395			432

Total deferred credits and other liabilities		2,743			2,646			2,809			2,646

Total liabilities		7,379			6,990			7,296			6,990

Commitments and Contingencies (see Note 15)
Equity
Membership interests		3,471			3,417			3,553			3,417
Accumulated other comprehensive loss⁽²⁾		(115	)		(99	)		(106	)		(99	)

Total equity		3,356			3,318			3,447			3,318

Total liabilities and equity	$	10,735		$	10,308		$	10,743		$	10,308

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


Six Months Ended June 30,	2016			2015
Nine Months Ended September 30,							2016			2015
(millions)
Operating Activities
Net income	$	203		$	246		$	286		$	357
Adjustments to reconcile net income to net cash provided by operating activities:
Gains on the sales of assets and equity method investment in Iroquois		(45	)		(71	)		(50	)		(123	)
Depreciation and amortization		95			104			150			157
Deferred income taxes and investment tax credits		125			55			204			75
Other adjustments		4			—			3			4
Changes in:
Accounts receivable		39			106			56			150
Affiliated receivables and payables		87			(15	)		91			(22	)
Deferred purchased gas costs, net		11			28			7			19
Prepayments		29			111			15			145
Accounts payable		(75	)		(132	)		(76	)		(112	)
Accrued interest, payroll and taxes		(28	)		(54	)		(7	)		(45	)
Other operating assets and liabilities		(120	)		(85	)		(176	)		(109	)

Net cash provided by operating activities		325			293			503			496

Investing Activities
Plant construction and other property additions		(393	)		(292	)		(610	)		(514	)
Proceeds from sale of equity method investment in Iroquois		7			—			7			—
Proceeds from assignments of shale development rights		5			28			10			80
Other		(5	)		(6	)		(10	)		(5	)

Net cash used in investing activities		(386	)		(270	)		(603	)		(439	)

Financing Activities
Issuance (repayment) of short-term debt, net		(153	)		360			(331	)		382
Issuance of long-term debt		680			—			680			—
Repayment of affiliated current borrowings, net		(95	)		(216	)		(95	)		(186	)
Distribution payments to parent		(150	)		(164	)		(150	)		(244	)
Other		(8	)		(1	)		(9	)		—

Net cash provided by (used in) financing activities		274			(21	)		95			(48	)

Increase in cash and cash equivalents		213			2
Increase (decrease) in cash and cash equivalents								(5	)		9
Cash and cash equivalents at beginning of period		13			9			13			9

Cash and cash equivalents at end of period	$	226		$	11		$	8		$	18

Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	42		$	37		$	42		$	46

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

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’ principal wholly-owned subsidiaries are DTI, East Ohio and Dominion Iroquois. In August 2016, DTI transferred its gathering and processing facilities to Dominion Gathering and Processing, Inc., a newly-formed wholly-owned subsidiary of Dominion Gas. See Note 3 for a description of operations acquired in the Dominion Questar Combination.

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, 2015.

In the Companies’ opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position as of ~~June~~September 30, 2016, their results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, their cash flows for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015 and Dominion’s ~~statement of~~changes in equity for the ~~six~~nine months ended ~~June~~September 30, 2016. 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~~September 30, 2016, Dominion owns the general partner and ~~64.8%~~65.0% 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~~September 30, 2016, Dominion owns 50% of the units in and consolidates Four Brothers and Three Cedars. SunEdison’s ownership interest in Four Brothers and Three Cedars, as well as Terra Nova Renewable Partners’ 33% interest in certain Dominion merchant solar projects, is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. See Note 3 for further information on transactions with SunEdison.

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’ 2015 Consolidated Financial Statements and Notes have been reclassified to conform to the 2016 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows, except for the reclassification of debt issuance costs as discussed in Note 2 to the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015.

Amounts disclosed for Dominion are inclusive of Virginia Power and/or Dominion Gas, where applicable.

~~Pursuant~~In September 2016, Dominion completed the Dominion Questar Combination and Dominion Questar became a wholly-owned subsidiary of Dominion. Dominion Questar is a Rockies-based integrated natural gas company that operates approximately

3,400 miles of gas transmission pipeline, 27,500 miles of gas distribution pipeline and 56 bcf of gas storage. Additionally, Dominion Questar develops and produces natural gas from cost-of-service reserves for its retail distribution customers. The Dominion Questar Combination provides Dominion with pipeline infrastructure that provides a principal source of gas supply to Western states. Dominion Questar’s regulated businesses will also provide further balance between Dominion’s electric and gas operations.

In accordance with the terms of the Dominion Questar Combination, ~~announced in February 2016, upon~~at closing, each share of issued and outstanding Dominion Questar common stock ~~issued and outstanding immediately prior to the closing will be~~was converted ~~automatically~~ into the right to receive ~~$25 in cash~~$25.00 per share ~~or approximately~~in cash. The total consideration was $4.4 billion ~~in total. In addition, Questar’s debt, which currently totals approximately $1.5~~based on 175.5 million shares of Dominion Questar outstanding at closing.

Dominion financed the Dominion Questar Combination through the: (1) August 2016 issuance of $1.4 billion ~~is expected to remain outstanding. Dominion entered into agreements with several~~ of ~~its lending banks pursuant to~~

~~which they have unfunded financing commitments to provide~~2016 Equity Units, (2) August 2016 issuance of $1.3 billion of senior notes, (3) September 2016 borrowing of $1.2 billion under a ~~$3.9 billion acquisition facility. In connection with receipt~~private placement term loan agreement and (4) $500 million of the proceeds from ~~Dominion’s~~the April 2016 issuance of common ~~stock, the acquisition facility was reduced from $3.9 billion to $3.14 billion in April 2016.~~stock. See Note 14 for more information. ~~At June 30, 2016, $500 million of such proceeds~~

Dominion Questar’s assets acquired and liabilities assumed were measured at estimated fair value at the closing date and are included in ~~restricted cash and cash equivalents in Dominion’s Consolidated Balance Sheets.~~the Dominion ~~intends to permanently finance the transaction in a manner that supports its existing credit ratings targets by issuing a combination~~Energy operating segment. The majority of ~~common stock, mandatory convertibles and debt at~~ Dominion ~~and indirectly through the issuance of securities at Dominion Midstream, the proceeds of which will be applied to pay Dominion for certain assets of Questar, which~~Questar’s operations are subject to ~~relevant approvals,~~the rate-setting authority of FERC, the Utah Commission and/or the Wyoming Commission and therefore are accounted for pursuant to ASC 980,Regulated Operations. The fair values of Dominion Questar’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.

The fair value of Dominion Questar’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions discussed above was determined using the income approach. In addition, the fair value of Dominion Questar’s 50% interest in White River Hub, accounted for under the equity method, was determined using the market approach and income approach. The valuations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future cash flows and future market prices.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill at the closing date. The goodwill reflects the value associated with enhancing Dominion’s regulated portfolio of businesses, including the expected increase in demand for low-carbon, natural gas-fired generation in the Western states and the expected continued growth of rate-regulated businesses located in a defined service area with a stable regulatory environment. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill.

The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at closing. The allocation is subject to change during the remainder of the measurement period, which ends one year from the closing date, as additional information is obtained about the facts and circumstances that existed at the closing date. Any material adjustments to provisional amounts identified during the measurement period will be ~~contributed to Dominion Midstream.~~recognized and disclosed in the reporting period in which the adjustment amounts are determined.


	Amount
(millions)
Total current assets	$	224
Investments⁽¹⁾		58
Property, plant and equipment⁽²⁾		4,120
Goodwill		3,111
Total deferred charges and other assets, excluding goodwill		75

Total Assets		7,588

Total current liabilities⁽³⁾		791
Long-term debt⁽⁴⁾		963
Deferred income taxes		798
Regulatory liabilities		259
Asset retirement obligations		160
Other deferred credits and other liabilities⁽⁵⁾		220

Total Liabilities		3,191

Total estimated purchase price	$	4,397

The transaction ~~requires~~required approval of Dominion Questar’s shareholders, ~~and~~ clearance from the Federal Trade Commission under the Hart-Scott-Rodino ~~Act.~~Act and approval from both the Utah Commission and the Wyoming Commission. In February 2016, the Federal Trade Commission granted antitrust approval of the Dominion Questar Combination under the Hart-Scott-Rodino Act. In ~~March~~May 2016, ~~Questar and~~ Dominion filed for review and approval, as required, from the Utah Public Service Commission and the Wyoming Public Service Commission, and provided information regarding the transaction to the Idaho Public Utilities Commission. In May 2016, Questar’s shareholders voted to approve the Dominion Questar Combination. ~~The~~In August 2016 and September 2016, approvals were granted by the Utah Commission and the Wyoming Commission, respectively. Information regarding the transaction was also provided to the Idaho Public Utilities Commission, who acknowledged the Dominion Questar Combination ~~contains certain termination rights~~in October 2016, and directed Dominion Questar to notify the Idaho Public Utilities Commission when it makes filings with the Utah Commission.

Approval of the Dominion Questar Combination in Utah and Wyoming was conditioned upon Dominion agreeing to the following:

The impact of the Dominion Questar Combination on Dominion’s operating revenue and net income attributable to Dominion in the Consolidated Statements of Income for both the three and nine months ended September 30, 2016, was an increase of $23 million and $5 million, respectively.

Dominion incurred transaction and ~~Questar,~~transition costs, of which $40 million and ~~provides that, upon termination~~$47 million was recorded in other operations and maintenance expense for the three and nine months ended September 30, 2016, respectively, and $13 million was recorded in interest and related charges for both the three and nine months ended September 30, 2016, in Dominion’s Consolidated Statements of Income. These costs consist of the amortization of financing costs, the charitable contribution commitment described above, employee-related expenses, professional fees, and other miscellaneous costs.

The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion assuming the Dominion Questar Combination had taken place on January 1, 2015. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.

In October 2016, Dominion entered into the Contribution Agreement under ~~specified circumstances,~~which Dominion ~~would be required~~will contribute Questar Pipeline to ~~pay a termination fee~~Dominion Midstream. Upon closing of $154 million to Questar and Questar would be required to pay Dominion a termination fee of $99 million. Subject to any remaining required regulatory approvals and meeting closing conditions, Dominion targets closingthe agreement, expected by the end of 2016, Dominion Midstream will become owner of all of the issued and outstanding membership interests of Questar Pipeline in exchange for consideration consisting of Dominion Midstream common and convertible preferred units with a combined value between $400 million and $725 million and cash between $565 million and $890 million, $300 million of which is considered a debt-financed distribution, for a total of $1.3 billion. In addition, under the terms of the Contribution Agreement, Dominion Midstream will repurchase approximately 6,657,000 common units from Dominion, and will repay its $301 million promissory note to Dominion. The cash proceeds from these transactions will be utilized to repay the $1.2 billion private placement term loan agreement borrowed in September 2016. Since Dominion consolidates Dominion Midstream for financial reporting purposes, the transactions associated with the Contribution Agreement will be eliminated upon consolidation and will not impact Dominion’s financial position or cash flows.

In June 2015, Dominion acquired 50% of the units in Four Brothers from SunEdison for $64 million of consideration, consisting of $2 million in cash and a $62 million payable. As of ~~June~~September 30, 2016, ~~an $11~~a $7 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. 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 and has contributed $370 million through June 30, 2016. The facilities ~~are expected to begin~~began commercial operations ~~by the end of~~during the third quarter of 2016, with generating capacity of approximately 320 ~~MW.~~MW, at a cost of approximately $670 million.

In September 2015, Dominion acquired 50% of the units in Three Cedars from SunEdison for $43 million of consideration, consisting of $6 million in cash and a $37 million payable. As of ~~June~~September 30, 2016, a $7$4 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Three Cedars’ purpose is to ~~develop and~~ operate three solar projects located in Utah, which ~~will~~ produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $425 million to construct. Dominion is obligated to contribute $276 million of capital to fund the construction of the projects and has contributed $223 million through June 30, 2016. The facilities ~~are expected to begin~~began commercial operations ~~by the end of~~during the third quarter of 2016, with generating capacity of approximately 210 ~~MW.~~MW, at a cost of approximately $450 million.

~~Long-term~~The Four Brothers and Three Cedars facilities operate under long-term power purchase, interconnection and operation and maintenance ~~agreements have been executed for both Four Brothers and Three Cedars.~~agreements. Dominion ~~expects to~~will claim 99% of the federal investment tax credits on the projects.

Dominion owns 50% of the voting interests in Four Brothers and Three Cedars and has a controlling financial interest over the entities through its rights to control operations. The allocation of the $64 million purchase price for Four Brothers resulted in $89 million of property, plant and equipment and $25 million of noncontrolling interest. The allocation of the $43 million purchase price for Three Cedars resulted in $65 million of property, plant and equipment and $22 million of noncontrolling interest. The noncontrolling interest for each entity 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. The acquired assets of Four Brothers and Three Cedars are included in the Dominion Generation operating segment.

Dominion has assumed the majority of the agreements to provide administrative and support services in connection with construction of the projects, operations and maintenance of the facilities and technical management services of the solar facilities. Costs related to services to be provided under these agreements were immaterial for the ~~six~~nine months ended ~~June~~September 30, 2016. Subsequent to Dominion’s acquisition of Four Brothers and Three Cedars, ~~through June 30, 2016,~~ SunEdison made contributions to Four Brothers and Three Cedars of ~~$265~~$281 million in aggregate through September 30, 2016, which are reflected as noncontrolling interests in Dominion’s Consolidated Balance Sheets.

In ~~April~~November 2016, ~~SunEdison filed for Chapter 11 bankruptcy; however, this is not expected to have a material adverse effect on Dominion,~~NRG acquired the 50% of units in Four Brothers orand Three ~~Cedars.~~Cedars previously held by SunEdison.

The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion in the ~~second quarter of~~nine months ended September 30, 2015. Long-term power purchase, interconnection and operation and maintenance agreements have been executed for all of the projects. Dominion has claimed federal investment tax credits on the projects. These projects are included in the Dominion Generation operating segment.

Completed Acquisition Date

Seller

Number
of
Projects

Project
Location

Project Name(s)

Initial
Acquisition
Cost
(millions)⁽¹⁾

Project
Cost
(millions)⁽²⁾

Date of
Commercial
Operations

MW
Capacity

Seller

Number
of
Projects

Project
Location

Project Name

Initial
Acquisition
Cost
(millions)⁽¹⁾

Project
Cost
(millions)⁽²⁾

Date of
Commercial
Operations

MW
Capacity

April 2015

EC&R NA Solar PV, LLC

California

Alamo

May 2015

EC&R NA Solar PV, LLC

California

Alamo

May 2015

April 2015

EDF Renewable Development, Inc.

California

Cottonwood⁽³⁾

106

May 2015

EDF Renewable Development, Inc.

California

Cottonwood⁽³⁾

106

May 2015

June 2015

EDF Renewable Development, Inc.

California

Catalina 2

July 2015

EDF Renewable Development, Inc.

California

Catalina 2

July 2015

SunPeak Solar, LLC

California

Imperial Valley 2

August 2015

In August 2016, Dominion entered into an agreement to acquire 100% of the equity interests of two solar projects in California from Solar Frontier Americas Holding, LLC for approximately $128 million in cash. The acquisition is expected to close prior to both projects commencing operations, which is expected by the end of 2017. The projects are expected to cost approximately $130 million once constructed, including the initial acquisition cost, and to generate approximately 50 MW combined.

In August 2016, Dominion entered into an agreement to acquire 100% of the equity interests of four solar projects in Virginia from Virginia Solar, LLC. The acquisition is expected to close during the fourth quarter of 2016, prior to the projects commencing operations by the end of 2017, for an amount to be determined based on the costs incurred through closing. The projects are expected to cost approximately $160 million once constructed, including the initial acquisition cost, and to generate approximately 80 MW combined.

In September 2016, Dominion entered into an agreement to acquire 100% of the equity interests of a solar project in Virginia from Community Energy Solar, LLC. The acquisition is expected to close during the first quarter of 2017, prior to the project commencing operations by the end of 2017, for an amount to be determined based on the costs incurred through closing. The project is expected to cost approximately $210 million once constructed, including the initial acquisition cost, and to generate approximately 100 MW.

In September 2015, Dominion signed an agreement to sell a noncontrolling interest (consisting of 33% of the equity interests) in all of its then currently wholly-owned merchant solar projects, 24 solar projects totaling approximately 425 MW, to SunEdison, including projects discussed in the table above. In December 2015, the sale of interest in 15 of the solar projects closed for $184 million with the sale of interest in the remaining projects completed in January 2016 for $117 million. Upon closing, SunEdison sold its interest in these projects to Terra Nova Renewable Partners. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion’s remaining 67% ownership in the projects upon the occurrence of certain events, none of which had occurred as of ~~June~~September 30, 2016 nor are expected to occur in the remainder of 2016.

In January 2015, Dominion completed the acquisition of 100% of the equity interests of DCG from SCANA Corporation for $497 million in cash, as adjusted for working capital. DCG 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 resulted in $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 $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 DCG are included in the Dominion Energy operating segment.

On March 24, 2015, DCG converted to a limited liability company under the laws of South Carolina and changed its name from Carolina Gas Transmission Corporation to DCG. On April 1, 2015, Dominion contributed 100% of the issued and outstanding membership interests of DCG 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, $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.

In December 2013, Dominion Gas closed on 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 Dominion Gas, 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 March 2015, Dominion Gas 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. In April 2016, Dominion Gas and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of a 32% partial interest in the remaining approximately 70,000 acres. This conveyance resulted in the recognition of the remaining $35 million ($21 million after-tax) of previously deferred revenue to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.

In March 2015, Dominion Gas 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 $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.

In September 2015, Dominion Gas closed on an agreement with a natural gas producer to convey approximately 16,000 acres of Utica and Point Pleasant Shale development rights underneath one of its natural gas storage fields. The agreement provided for a payment to Dominion Gas, subject to customary adjustments, of $52 million and an overriding royalty interest in gas produced from the acreage. In September 2015, Dominion Gas received proceeds of $52 million associated with the conveyance of the acreage, resulting in a $52 million ($29 million after-tax) gain, included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.

In November 2014, Dominion Gas closed on an agreement with a natural gas producer to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. In connection with that agreement, in January 2016, Dominion Gas conveyed approximately 2,000 acres of Marcellus Shale development rights and received proceeds of $5 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in a $5 million ($3 million after-tax) ~~gain, included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.~~gain. Also in connection with that agreement, in July 2016, Dominion Gas conveyed ~~to a natural gas producer~~ approximately 2,000 acres of Marcellus Shale development rights ~~underneath one of its natural gas storage fields~~ and received proceeds of $5 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in a $5 million ($3 million after-tax) gain. These gains are included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Dominion
Electric sales:
Regulated	$	2,147	$	2,020	$	5,707	$	5,911
Nonregulated		399		388		1,123		1,145
Gas sales:
Regulated		46		21		137		168
Nonregulated		87		66		259		361
Gas transportation and storage		378		365		1,162		1,221
Other		75		111		263		321

Total operating revenue	$	3,132	$	2,971	$	8,651	$	9,127

Virginia Power
Regulated electric sales	$	2,147	$	2,020	$	5,707	$	5,911
Other		64		38		170		97

Total operating revenue	$	2,211	$	2,058	$	5,877	$	6,008

Dominion Gas
Gas sales:
Regulated	$	28	$	9	$	69	$	87
Nonregulated		1		1		8		5
Gas transportation and storage		303		302		955		1,035
NGL revenue		19		20		45		71
Other		31		33		104		93

Total operating revenue	$	382	$	365	$	1,181	$	1,291

For continuing operations, including noncontrolling interests, the statutory United States federal income tax rate reconciles to the Companies’ effective income tax rate as follows:


	Dominion						Virginia Power						Dominion Gas						Dominion						Virginia Power						Dominion Gas
Six Months Ended June 30,	2016			2015			2016			2015			2016			2015
Nine Months Ended September 30,																			2016			2015			2016			2015			2016			2015
United States statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		4.3			3.3			4.0			3.8			3.8			3.9			3.7			4.0			3.9			4.2			0.8			4.1
Investment tax credits		(9.9	)		(2.7	)		—			—			—			—			(10.4	)		(3.5	)		—			—			—			—
Production tax credits		(0.8	)		(0.8	)		(0.6	)		(0.5	)		—			—			(0.8	)		(0.8	)		(0.5	)		(0.5	)		—			—
State legislative change		(1.3	)		—			—			—			—			—			(0.8	)		(0.2	)		—			—			—			—
Other, net		(2.3	)		(1.0	)		(0.5	)		(0.7	)		(0.1	)		—			(2.1	)		(0.7	)		(0.5	)		(0.2	)		0.4			0.4

Effective tax rate		25.0	%		33.8	%		37.9	%		37.6	%		38.7	%		38.9	%		24.6	%		33.8	%		37.9	%		38.5	%		36.2	%		39.5	%

AsIn 2016, Dominion’s effective tax rate reflects $23 million of ~~June~~previously unrecognized tax benefits resulting from a settlement with a tax authority ($12 million) and a legislative change ($11 million). The settlement is also reflected in Dominion Gas’ 2016 effective tax rate. Otherwise, as of September 30, 2016, 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, ~~2015 for a discussion of these unrecognized tax benefits.~~2015.

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015		2016		2015		2016		2015
(millions, except EPS)
Net income attributable to Dominion	$	452	$	413	$	976	$	949	$	690	$	593	$	1,666	$	1,542

Average shares of common stock outstanding – Basic		615.6		591.5		606.1		589.7		625.9		594.6		612.8		591.3
Net effect of dilutive securities⁽¹⁾		1.4		1.0		1.5		1.5		0.1		0.9		1.0		1.4

Average shares of common stock outstanding – Diluted		617.0		592.5		607.6		591.2		626.0		595.5		613.8		592.7

Earnings Per Common Share – Basic	$	0.73	$	0.70	$	1.61	$	1.61	$	1.10	$	1.00	$	2.72	$	2.61
Earnings Per Common Share – Diluted	$	0.73	$	0.70	$	1.61	$	1.60	$	1.10	$	1.00	$	2.71	$	2.60

The 2014 Equity Units and 2016 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, as the dilutive stock price threshold was not met.

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			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, 2016
Three Months Ended September 30, 2016
Beginning balance																$	(241	)	$	535		$	(781	)	$	(6	)	$	(493	)
Other comprehensive income before reclassifications: gains																	14			31			15			—			60
Amounts reclassified from AOCI⁽¹⁾: (gains) losses																	(34	)		(13	)		9			—			(38	)

Net current-period other comprehensive income (loss)																	(20	)		18			24			—			22

Ending balance																$	(261	)	$	553		$	(757	)	$	(6	)	$	(471	)

Three Months Ended September 30, 2015
Beginning balance	$	(186	)	$	517		$	(789	)	$	(5	)	$	(463	)	$	(146	)	$	519		$	(754	)	$	(5	)	$	(386	)
Other comprehensive income before reclassifications: gains (losses)		(11	)		26			—			(1	)		14			(7	)		(59	)		(9	)		1			(74	)
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(44	)		(8	)		8			—			(44	)		(53	)		(2	)		14			—			(41	)

Net current-period other comprehensive income (loss)		(55	)		18			8			(1	)		(30	)		(60	)		(61	)		5			1			(115	)

Ending balance	$	(241	)	$	535		$	(781	)	$	(6	)	$	(493	)	$	(206	)	$	458		$	(749	)	$	(4	)	$	(501	)

Three Months Ended June 30, 2015
Nine Months Ended September 30, 2016
Beginning balance	$	(177	)	$	542		$	(769	)	$	(5	)	$	(409	)	$	(176	)	$	504		$	(797	)	$	(5	)	$	(474	)
Other comprehensive income before reclassifications: gains (losses)		92			(11	)		3			—			84			56			72			15			(1	)		142
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(61	)		(12	)		12			—			(61	)		(141	)		(23	)		25			—			(139	)
														��
Net current-period other comprehensive income (loss)		31			(23	)		15			—			23			(85	)		49			40			(1	)		3

Ending balance	$	(146	)	$	519		$	(754	)	$	(5	)	$	(386	)	$	(261	)	$	553		$	(757	)	$	(6	)	$	(471	)

Six Months Ended June 30, 2016
Nine Months Ended September 30, 2015
Beginning balance	$	(176	)	$	504		$	(797	)	$	(5	)	$	(474	)	$	(178	)	$	548		$	(782	)	$	(4	)	$	(416	)
Other comprehensive income before reclassifications: gains (losses)		42			41			—			(1	)		82			25			(55	)		(6	)		—			(36	)
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(107	)		(10	)		16			—			(101	)		(53	)		(35	)		39			—			(49	)

Net current-period other comprehensive income (loss)		(65	)		31			16			(1	)		(19	)		(28	)		(90	)		33			—			(85	)

Ending balance	$	(241	)	$	535		$	(781	)	$	(6	)	$	(493	)	$	(206	)	$	458		$	(749	)	$	(4	)	$	(501	)

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	)

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	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Three Months Ended June 30, 2016
Three Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(87	)	Operating revenue	$	(64	)	Operating revenue
		2		Purchased gas		1		Purchased gas
		3		Electric fuel and other energy-related purchases		1		Electric fuel and other energy-related purchases
Interest rate contracts		8		Interest and related charges		10		Interest and related charges
Foreign currency contracts		2		Other income		(3	)	Other income
		(72	)
						(55	)
Tax		28		Income tax expense		21		Income tax expense

	$	(44	)		$	(34	)


Details About AOCI Components	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(20	)	Other income	$	(25	)	Other income
Impairment		7		Other income		5		Other income

		(13	)			(20	)
Tax		5		Income tax expense		7		Income tax expense

	$	(8	)		$	(13	)

Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(3	)	Other operations and maintenance	$	(4	)	Other operations and maintenance
Actuarial (gains) losses		17		Other operations and maintenance		17		Other operations and maintenance

		14				13
Tax		(6	)	Income tax expense		(4	)	Income tax expense

	$	8			$	9

Three Months Ended June 30, 2015
Three Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(107	)	Operating revenue	$	(87	)	Operating revenue
		2		Purchased gas		2		Purchased gas
Interest rate contracts		3		Interest and related charges		2		Interest and related charges

		(102	)			(83	)
Tax		41		Income tax expense		30		Income tax expense

	$	(61	)		$	(53	)

Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(25	)	Other income	$	(18	)	Other income
Impairment		5		Other income		16		Other income

		(20	)			(2	)
Tax		8		Income tax expense		—		Income tax expense

	$	(12	)		$	(2	)

Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(3	)	Other operations and maintenance	$	(3	)	Other operations and maintenance
Actuarial (gains) losses		24		Other operations and maintenance		24		Other operations and maintenance

		21				21
Tax		(9	)	Income tax expense		(7	)	Income tax expense

	$	12			$	14

Six Months Ended June 30, 2016
Nine Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(201	)	Operating revenue	$	(266	)	Operating revenue
		8		Purchased gas		9		Purchased gas
		6		Electric fuel and other energy-related purchases		8		Electric fuel and other energy-related purchases
Interest rate contracts		11		Interest and related charges		21		Interest and related charges
Foreign currency contracts		2		Other income		(1	)	Other income

		(174	)			(229	)
Tax		67		Income tax expense		88		Income tax expense

	$	(107	)		$	(141	)

Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities					$	(55	)	Other income
Impairment						19		Other income

						(36	)
Tax						13		Income tax expense

					$	(23	)


Details About AOCI Components	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(30	)	Other income
Impairment		14		Other income

		(16	)
Tax		6		Income tax expense

	$	(10	)

Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(7	)	Other operations and maintenance	$	(11	)	Other operations and maintenance
Actuarial (gains) losses		35		Other operations and maintenance		52		Other operations and maintenance

		28				41
Tax		(12	)	Income tax expense		(16	)	Income tax expense

	$	16			$	25

Six Months Ended June 30, 2015
Nine Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(15	)	Operating revenue	$	(103	)	Operating revenue
		7		Purchased gas
		(1	)	Electric fuel and other energy-related purchases		9		Purchased gas
Interest rate contracts		5		Interest and related charges		7		Interest and related charges

		(4	)			(87	)
Tax		2		Income tax expense		34		Income tax expense

	$	(2	)		$	(53	)

Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(64	)	Other income	$	(82	)	Other income
Impairment		11		Other income		27		Other income

		(53	)			(55	)
Tax		20		Income tax expense		20		Income tax expense

	$	(33	)		$	(35	)

Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(6	)	Other operations and maintenance	$	(9	)	Other operations and maintenance
Actuarial (gains) losses		49		Other operations and maintenance		73		Other operations and maintenance

		43				64
Tax		(18	)	Income tax expense		(25	)	Income tax expense

	$	25			$	39

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			Deferred Gains and Losses on Derivatives- Hedging Activities			Unrecognized Pension and Other Postretirement Benefit Costs			Total
(millions)
Three Months Ended June 30, 2016
Beginning balance	$	(25	)	$	(82	)	$	(107	)
Other comprehensive income before reclassifications: losses		(9	)		—			(9	)
Amounts reclassified from AOCI⁽¹⁾: losses		—			1			1

Net current-period other comprehensive income (loss)		(9	)		1			(8	)

Ending balance	$	(34	)	$	(81	)	$	(115	)

Three Months Ended June 30, 2015
Three Months Ended September 30, 2016
Beginning balance	$	(24	)	$	(65	)	$	(89	)	$	(34	)	$	(81	)	$	(115	)
Other comprehensive income before reclassifications: gains		3			—			3			9			—			9
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(1	)		1			—			(1	)		1			—

Net current-period other comprehensive income		2			1			3			8			1			9

Ending balance	$	(22	)	$	(64	)	$	(86	)	$	(26	)	$	(80	)	$	(106	)

Six Months Ended June 30, 2016
Three Months Ended September 30, 2015
Beginning balance										$	(22	)	$	(64	)	$	(86	)
Other comprehensive income before reclassifications: gains											3			—			3
Amounts reclassified from AOCI⁽¹⁾: (gains) losses											(2	)		1			(1	)

Net current-period other comprehensive income											1			1			2

Ending balance										$	(21	)	$	(63	)	$	(84	)

Nine Months Ended September 30, 2016
Beginning balance	$	(17	)	$	(82	)	$	(99	)	$	(17	)	$	(82	)	$	(99	)
Other comprehensive income before reclassifications: losses		(15	)		—			(15	)		(6	)		—			(6	)
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(2	)		1			(1	)		(3	)		2			(1	)

Net current-period other comprehensive income (loss)		(17	)		1			(16	)		(9	)		2			(7	)

Ending balance	$	(34	)	$	(81	)	$	(115	)	$	(26	)	$	(80	)	$	(106	)

Six Months Ended June 30, 2015
Nine Months Ended September 30, 2015
Beginning balance	$	(20	)	$	(66	)	$	(86	)	$	(20	)	$	(66	)	$	(86	)
Other comprehensive income before reclassifications: losses		(1	)		—			(1	)
Other comprehensive income before reclassifications: gains											2			—			2
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(1	)		2			1			(3	)		3			—

Net current-period other comprehensive income (loss)		(2	)		2			—			(1	)		3			2

Ending balance	$	(22	)	$	(64	)	$	(86	)	$	(21	)	$	(63	)	$	(84	)

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

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, 2015. See Note 9 in this report for further information about the Companies’ derivatives and hedge accounting activities.

Dominion and Dominion Gas apply fair value measurements to foreign currency swaps used to manage the foreign currency exchange rate risk related to interest and principal payments denominated in foreign currencies. These swaps are designated as cash flow hedges for accounting purposes and are categorized as Level 2.

The inputs and assumptions used in measuring the fair value for foreign currency swaps include the following:

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, and risk-free rate of ~~return, and credit spreads.~~return. 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~~September 30, 2016. 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⁾			Fair Value (millions)		Valuation Techniques	Unobservable Input	Range			Weighted Average⁽¹⁾
Assets
Physical and financial forwards and futures:
Natural gas⁽²⁾	$	123	Discounted cash flow	Market price (per Dth)⁽³⁾		(2) - 7			—		$	85	Discounted cash flow	Market price (per Dth)⁽³⁾		(2) - 7			—
				Credit spread⁽⁴⁾		1% - 6	%		3	%
FTRs		6	Discounted cash flow	Market price (per MWh)⁽³⁾		(8) - 3			1			7	Discounted cash flow	Market price (per MWh)⁽³⁾		(6) - 6			1
Physical and financial options:
Natural gas		8	Option model	Market price (per Dth)⁽³⁾		2 - 7			4			4	Option model	Market price (per Dth)⁽³⁾		2 - 7			3
				Price volatility⁽⁵⁾		20% - 42	%		25	%				Price volatility⁽⁴⁾		19% - 46	%		24	%

Total assets	$	137									$	96

Liabilities
Physical and financial forwards and futures:
Natural gas⁽²⁾	$	5	Discounted cash flow	Market price (per Dth)⁽³⁾		(1) - 4			3		$	4	Discounted cash flow	Market price (per Dth)⁽³⁾		(2) - 4			1
FTRs		7	Discounted cash flow	Market price (per MWh)⁽³⁾		(2) - 5			1			2	Discounted cash flow	Market price (per MWh)⁽³⁾		(11) - 6			1
Physical and financial options:
Natural gas		1	Option model	Market price (per Dth)⁽³⁾		2 - 4			3			1	Option model	Market price (per Dth)⁽³⁾		2 - 4			3
				Price volatility⁽⁵⁾		29% - 42	%		36	%				Price volatility⁽⁴⁾		30% - 46	%		38	%

Total liabilities	$	13									$	7

(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.

Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

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		Level 1		Level 2		Level 3		Total
(millions)
At June 30, 2016
At September 30, 2016
Assets
Derivatives:
Commodity	$	—	$	192	$	137	$	329	$	—	$	172	$	96	$	268
Interest rate		—		25		—		25		—		19		—		19
Foreign currency										—		8		—		8
Investments⁽¹⁾:
Equity securities:
United States:
Large cap		2,617		—		—		2,617		2,712		—		—		2,712
REIT										67		—		—		67
Other		5		—		—		5		6		—		—		6
REIT		72		—		—		72
Non-United States:
Large cap		10		—		—		10		10		—		—		10
Fixed income:
Corporate debt instruments		—		498		—		498		—		518		—		518
United States Treasury securities and agency debentures		462		236		—		698		438		231		—		669
State and municipal		—		364		—		364		—		372		—		372
Other		—		112		—		112		—		109		—		109
Cash equivalents and other		5		—		—		5		8		—		—		8

Total assets	$	3,171	$	1,427	$	137	$	4,735	$	3,241	$	1,429	$	96	$	4,766

Liabilities
Derivatives:
Commodity	$	—	$	87	$	13	$	100	$	—	$	104	$	7	$	111
Interest rate		—		366		—		366		—		307		—		307
Foreign currency		—		7		—		7		—		4		—		4

Total liabilities	$	—	$	460	$	13	$	473	$	—	$	415	$	7	$	422


	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
At December 31, 2015
Assets
Derivatives:
Commodity	$	1	$	249	$	114	$	364	$	1	$	249	$	114	$	364
Interest rate		—		24		—		24		—		24		—		24
Investments⁽¹⁾:
Equity securities:
United States:
Large cap		2,547		—		—		2,547		2,547		—		—		2,547
REIT										63		—		—		63
Other		5		—		—		5		5		—		—		5
REIT		63		—		—		63
Non-United States:
Large cap		10		—		—		10		10		—		—		10
Fixed income:
Corporate debt instruments		—		437		—		437		—		437		—		437
United States Treasury securities and agency debentures		458		201		—		659		458		201		—		659
State and municipal		—		376		—		376		—		376		—		376
Other		—		100		—		100		—		100		—		100
Cash equivalents and other		2		2		—		4		2		2		—		4

Total assets	$	3,086	$	1,389	$	114	$	4,589	$	3,086	$	1,389	$	114	$	4,589

Liabilities
Derivatives:
Commodity	$	—	$	141	$	19	$	160	$	—	$	141	$	19	$	160
Interest rate		—		183		—		183		—		183		—		183

Total liabilities	$	—	$	324	$	19	$	343	$	—	$	324	$	19	$	343

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,						Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015			2016			2015			2016			2015
(millions)
Beginning balance	$	109		$	76		$	95		$	107		$	124		$	71		$	95		$	107
Total realized and unrealized gains (losses):
Included in earnings		(10	)		(5	)		(17	)		10			(7	)		(9	)		(23	)		1
Included in other comprehensive income (loss)		—			(1	)		3			(12	)		—			5			2			(7	)
Included in regulatory assets/liabilities		15			(5	)		32			(29	)		(37	)		47			(5	)		18
Settlements		10			6			18			(8	)		9			10			27			1
Transfers out of Level 3		—			—			(7	)		3			—			(1	)		(7	)		3

Ending balance	$	124		$	71		$	124		$	71		$	89		$	123		$	89		$	123

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

The following table presents Dominion’s classification of gains and losses included in earnings in the Level 3 fair value category. 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 months ended June 30, 2016 and 2015.


	Operating Revenue		Electric Fuel and Other Energy- Related Purchases			Total			Operating Revenue		Electric Fuel and Other Energy- Related Purchases			Total
(millions)
Three Months Ended June 30, 2016
Three Months Ended September 30, 2016
Total gains (losses) included in earnings	$	—	$	(10	)	$	(10	)	$	—	$	(7	)	$	(7	)

Three Months Ended June 30, 2015
Total gains (losses) included in earnings	$	—	$	(5	)	$	(5	)

Six Months Ended June 30, 2016
Three Months Ended September 30, 2015
Total gains (losses) included in earnings	$	—	$	(17	)	$	(17	)	$	—	$	(9	)	$	(9	)
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
Nine Months Ended September 30, 2016
Total gains (losses) included in earnings									$	—	$	(23	)	$	(23	)

Nine Months Ended September 30, 2015
Total gains (losses) included in earnings	$	2	$	8		$	10		$	2	$	(1	)	$	1
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	)		—			1		—			1

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at ~~June~~September 30, 2016. 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⁾			Fair Value (millions)		Valuation Techniques	Unobservable Input	Range			Weighted Average⁽¹⁾
Assets
Physical and financial forwards and futures:
Natural gas⁽²⁾	$	121	Discounted cash flow	Market price (per Dth)⁽³⁾		(2) - 7			—		$	81	Discounted cash flow	Market price (per Dth)⁽³⁾		(2) - 7			—
				Credit spread⁽⁴⁾		1% - 6	%		3	%
FTRs		6	Discounted cash flow	Market price (per MWh)⁽³⁾		(8) - 3			1			7	Discounted cash flow	Market price (per MWh)⁽³⁾		(6) - 6			1
Physical and financial options:
Natural gas		5	Option model	Market price (per Dth)⁽³⁾		2 - 7			4			2	Option model	Market price (per Dth)⁽³⁾		2 - 7			3
				Price volatility⁽⁵⁾		20% - 33	%		24	%
														Price volatility⁽⁴⁾		19% - 33	%		24	%
Total assets	$	132									$	90

Liabilities
Physical and financial forwards and futures:
FTRs	$	7	Discounted cash flow	Market price (per MWh)⁽³⁾		(2) - 5			1		$	2	Discounted cash flow	Market price (per MWh)⁽³⁾		(11) - 6			1

Total liabilities	$	7									$	2

Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

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		Level 1		Level 2		Level 3			Total
(millions)
At June 30, 2016
At September 30, 2016
Assets
Derivatives:
Commodity	$	—	$	31	$	132	$	163	$	—	$	26	$	90		$	116
Interest rate										—		2		—			2
Investments⁽¹⁾:
Equity securities:
United States large cap		1,137		—		—		1,137		1,183		—		—			1,183
REIT		72		—		—		72		67		—		—			67
Fixed income:
Corporate debt instruments		—		283		—		283		—		298		—			298
United States Treasury securities and agency debentures		166		111		—		277		144		107		—			251
State and municipal		—		159		—		159		—		174		—			174
Other		—		48		—		48		—		29		—			29

Total assets	$	1,375	$	632	$	132	$	2,139	$	1,394	$	636	$	90		$	2,120

Liabilities
Derivatives:
Commodity	$	—	$	10	$	7	$	17	$	—	$	22	$	2		$	24
Interest rate		—		257		—		257		—		267		—			267

Total liabilities	$	—	$	267	$	7	$	274	$	—	$	289	$	2		$	291

At December 31, 2015
Assets
Derivatives:
Commodity	$	—	$	13	$	101	$	114	$	—	$	13	$	101		$	114
Interest rate		—		13		—		13		—		13		—			13
Investments⁽¹⁾:
Equity securities:
United States large cap		1,100		—		—		1,100		1,100		—		—			1,100
REIT		63		—		—		63		63		—		—			63
Fixed income:
Corporate debt instruments		—		238		—		238		—		238		—			238
United States Treasury securities and agency debentures		180		79		—		259		180		79		—			259
State and municipal		—		175		—		175		—		175		—			175
Other		—		34		—		34		—		34		—			34

Total assets	$	1,343	$	552	$	101	$	1,996	$	1,343	$	552	$	101	��	$	1,996

Liabilities
Derivatives:
Commodity	$	—	$	19	$	8	$	27	$	—	$	19	$	8		$	27
Interest rate		—		59		—		59		—		59		—			59

Total liabilities	$	—	$	78	$	8	$	86	$	—	$	78	$	8		$	86

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,						Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015			2016			2015			2016			2015
(millions)
Beginning balance	$	110		$	78		$	93		$	102		$	125		$	73		$	93		$	102
Total realized and unrealized gains (losses):
Included in earnings		(9	)		(5	)		(17	)		8			(7	)		(10	)		(24	)		(1	)
Included in regulatory assets/liabilities		15			(5	)		32			(29	)		(37	)		47			(5	)		18
Settlements		9			5			17			(8	)		7			10			24			1

Ending balance	$	125		$	73		$	125		$	73		$	88		$	120		$	88		$	120

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~~nine months ended ~~June~~September 30, 2016 and 2015. 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~~nine months ended ~~June~~September 30, 2016 and 2015.

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		Level 1		Level 2		Level 3		Total
(millions)
At June 30, 2016
At September 30, 2016
Assets
Commodity	$	—	$	3	$	—	$	3	$	—	$	6	$	—	$	6
Foreign currency										—		8		—		8

Total Assets	$	—	$	3	$	—	$	3	$	—	$	14	$	—	$	14
Liabilities
Commodity	$	—	$	5	$	—	$	5	$	—	$	2	$	—	$	2
Foreign currency		—		7		—		7		—		4		—		4

Total liabilities	$	—	$	12	$	—	$	12	$	—	$	6	$	—	$	6

At December 31, 2015
Assets
Commodity	$	—	$	5	$	6	$	11	$	—	$	5	$	6	$	11

Total Assets	$	—	$	5	$	6	$	11	$	—	$	5	$	6	$	11
Liabilities
Interest rate	$	—	$	14	$	—	$	14	$	—	$	14	$	—	$	14

Total liabilities	$	—	$	14	$	—	$	14	$	—	$	14	$	—	$	14

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 September 30,					Nine Months Ended September 30,
	2016		2015			2016			2015
(millions)
Beginning balance	$	—	$	(1	)	$	6		$	2
Total realized and unrealized gains (losses):
Included in earnings		—		—			—			1
Included in other comprehensive income (loss)		—		5			2			(7	)
Settlements		—		—			—			(1	)
Transfers out of Level 3		—		—			(8	)		9

Ending balance	$	—	$	4		$	—		$	4

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~~nine months ended ~~June~~September 30, 2015. 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~~nine months ended ~~June~~September 30, 2016 and 2015.

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 and cash equivalents,~~ customer, affiliated, 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, 2016				December 31, 2015				September 30, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value⁽¹⁾		Carrying Amount		Estimated Fair Value⁽¹⁾		Carrying Amount		Estimated Fair Value⁽¹⁾		Carrying Amount		Estimated Fair Value⁽¹⁾
(millions)
Dominion
Long-term debt, including securities due within one year⁽²⁾	$	22,754	$	25,400	$	21,873	$	23,210	$	26,287	$	29,077	$	21,873	$	23,210
Junior subordinated notes⁽³⁾		2,399		2,310		1,340		1,192		2,980		3,030		1,340		1,192
Remarketable subordinated notes⁽³⁾		982		1,037		2,080		2,129		2,371		2,392		2,080		2,129

Virginia Power
Long-term debt, including securities due within one year⁽³⁾	$	9,661	$	11,329	$	9,368	$	10,400	$	9,642	$	11,259	$	9,368	$	10,400

Dominion Gas
Long-term debt, including securities due within one year⁽⁴⁾	$	3,941	$	4,116	$	3,269	$	3,299	$	3,945	$	4,139	$	3,269	$	3,299

The Companies’ accounting policies, 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, 2015. 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.

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, 2016						December 31, 2015						September 30, 2016						December 31, 2015
	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		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	$	231	$	—	$	231	$	217	$	—	$	217	$	173	$	—	$	173	$	217	$	—	$	217
Exchange		91		—		91		138		—		138		88		—		88		138		—		138
Interest rate contracts:
Over-the-counter		25		—		25		24		—		24		19		—		19		24		—		24
Foreign currency contracts:
Over-the-counter														8		—		8		—		—		—

Total derivatives, subject to a master netting or similar arrangement		347		—		347		379		—		379		288		—		288		379		—		379
Total derivatives, not subject to a master netting or similar arrangement		7		—		7		9		—		9		7		—		7		9		—		9

Total	$	354	$	—	$	354	$	388	$	—	$	388	$	295	$	—	$	295	$	388	$	—	$	388


			September 30, 2016								December 31, 2015
			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	$	173	$	20	$	—	$	153	$	217	$	37	$	—	$	180
Exchange		88		63		—		25		138		82		—		56
Interest rate contracts:
Over-the-counter		19		10		—		9		24		22		—		2
Foreign currency contracts:
Over-the-counter		8		4		—		4		—		—		—		—

Total	$	288	$	97	$	—	$	191	$	379	$	141	$	—	$	238


			June 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet						September 30, 2016						December 31, 2015
	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		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)
Commodity contracts:
Over-the-counter	$	231	$	16	$	—	$	215	$	217	$	37	$	—	$	180	$	43	$	—	$	43	$	70	$	—	$	70
Exchange		91		63		—		28		138		82		—		56		63		—		63		82		—		82
Interest rate contracts:
Over-the-counter		25		15		—		10		24		22		—		2		307		—		307		183		—		183
Foreign currency contracts:
Over-the-counter																		4		—		4		—		—		—

Total derivatives, subject to a master netting or similar arrangement																		417		—		417		335		—		335
Total derivatives, not subject to a master netting or similar arrangement																		5		—		5		8		—		8

Total	$	347	$	94	$	—	$	253	$	379	$	141	$	—	$	238	$	422	$	—	$	422	$	343	$	—	$	343

   June 30, 2016    December 31, 2015
   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)
Commodity contracts:

Over-the-counter
   $ 32       $ —         $ 32       $ 70       $ —         $ 70
Exchange
   63       —         63       82       —         82
Interest rate contracts:

Over-the-counter
   366       —         366       183       —         183
Foreign currency contracts:

Over-the-counter
   7       —         7       —         —         —












Total derivatives, subject to a master netting or similar arrangement
   468       —         468       335       —         335
Total derivatives, not subject to a master netting or similar arrangement
   5       —         5       8       —         8












Total
   $ 473       $ —         $ 473       $ 343       $ —         $ 343


			June 30, 2016								December 31, 2015								September 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet								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		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)
Commodity contracts:
Over-the-counter	$	32	$	16	$	1	$	15	$	70	$	37	$	—	$	33	$	43	$	20	$	—	$	23	$	70	$	37	$	—	$	33
Exchange		63		63		—		—		82		82		—		—		63		63		—		—		82		82		—		—
Interest rate contracts:
Over-the-counter		366		15		—		351		183		22		—		161		307		10		—		297		183		22		—		161
Foreign currency contracts:
Over-the-counter		7		—		—		7		—		—		—		—		4		4		—		—		—		—		—		—

Total	$	468	$	94	$	1	$	373	$	335	$	141	$	—	$	194	$	417	$	97	$	—	$	320	$	335	$	141	$	—	$	194

The following table presents the volume of Dominion’s derivative activity at ~~June~~September 30, 2016. 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		Current		Noncurrent
Natural Gas (bcf):
Fixed price⁽¹⁾		125		38		104		23
Basis		190		580		261		626
Electricity (MWh):
Fixed price		11,749,639		1,978,640		8,274,639		659,440
FTRs		99,882,813		—		72,352,190		—
Liquids (Gal)⁽²⁾		59,807,554		—		39,269,554		—
Interest rate⁽³⁾	$	2,400,000,000	$	2,100,000,000	$	2,200,000,000	$	1,600,000,000
Foreign currency⁽³⁾⁽⁴⁾	$	—	$	280,000,000	$	—	$	280,000,000

For the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, 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~~September 30, 2016:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term		AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	10		$	9			22 months	$	(2	)	$	(2	)		39 months
Electricity		65			65			18 months		44			42			15 months
Other		(1	)		(1	)		9 months		(1	)		(1	)		6 months
Interest rate		(312	)		(23	)		381 months		(304	)		(26	)		378 months
Foreign currency		(3	)		(3	)		120 months		2			—			117 months

Total	$	(241	)	$	47				$	(261	)	$	13

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, interest rates, and foreign currency exchange rates.

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		Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At June 30, 2016
At September 30, 2016
ASSETS
Current Assets
Commodity	$	67	$	121	$	188	$	59	$	105	$	164
Interest rate		4		—		4		9		—		9

Total current derivative assets⁽¹⁾		71		121		192		68		105		173

Noncurrent Assets
Commodity		6		135		141		4		100		104
Interest rate		21		—		21		10		—		10
Foreign currency								8		—		8

Total noncurrent derivative assets⁽²⁾		27		135		162		22		100		122

Total derivative assets	$	98	$	256	$	354	$	90	$	205	$	295

LIABILITIES
Current Liabilities
Commodity	$	27	$	61	$	88	$	22	$	78	$	100
Interest rate		178		—		178		182		—		182
Foreign currency		5		—		5		4		—		4

Total current derivative liabilities⁽³⁾		210		61		271		208		78		286

Noncurrent Liabilities
Commodity		5		7		12		1		10		11
Interest rate		188		—		188		125		—		125
Foreign currency		2		—		2

Total noncurrent derivative liabilities⁽⁴⁾		195		7		202		126		10		136

Total derivative liabilities	$	405	$	68	$	473	$	334	$	88	$	422

At December 31, 2015
ASSETS
Current Assets
Commodity	$	101	$	151	$	252	$	101	$	151	$	252
Interest rate		3		—		3		3		—		3

Total current derivative assets⁽¹⁾		104		151		255		104		151		255

Noncurrent Assets
Commodity		3		109		112		3		109		112
Interest rate		21		—		21		21		—		21

Total noncurrent derivative assets⁽²⁾		24		109		133		24		109		133

Total derivative assets	$	128	$	260	$	388	$	128	$	260	$	388

LIABILITIES
Current Liabilities
Commodity	$	32	$	116	$	148	$	32	$	116	$	148
Interest rate		164		—		164		164		—		164

Total current derivative liabilities⁽³⁾		196		116		312		196		116		312

Noncurrent Liabilities
Commodity		—		12		12		—		12		12
Interest rate		19		—		19		19		—		19

Total noncurrent derivative liabilities⁽⁴⁾		19		12		31		19		12		31

Total derivative liabilities	$	215	$	128	$	343	$	215	$	128	$	343

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⁾			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, 2016
Three Months Ended September 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	87								$	64
Purchased gas					(2	)								(1	)
Electric fuel and other energy-related purchases					(3	)								(1	)

Total commodity	$	12		$	82		$	—		$	7		$	62		$	—

Interest rate⁽³⁾		(23	)		(8	)		(108	)		3			(10	)		(16	)
Foreign currency⁽⁴⁾		(7	)		(2	)		—			12			3			—

Total	$	(18	)	$	72		$	(108	)	$	22		$	55		$	(16	)

Three Months Ended June 30, 2015
Three Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	107								$	87
Purchased gas					(2	)								(2	)

Total commodity	$	94		$	105		$	—		$	64		$	85		$	—

Interest rate⁽³⁾		57			(3	)		(91	)		(71	)		(2	)		(69	)

Total	$	151		$	102		$	(91	)	$	(7	)	$	83		$	(69	)

Six Months Ended June 30, 2016
Nine Months Ended September 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	201								$	266
Purchased gas					(8	)								(9	)
Electric fuel and other energy-related purchases					(6	)								(8	)

Total commodity	$	185		$	187		$	—		$	193		$	249		$	—

Interest rate⁽³⁾		(110	)		(11	)		(241	)		(107	)		(21	)		(258	)
Foreign currency⁽⁴⁾		(7	)		(2	)		—			4			1			—

Total	$	68		$	174		$	(241	)	$	90		$	229		$	(258	)

Six Months Ended June 30, 2015
Nine Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	15								$	103
Purchased gas					(7	)								(9	)
Electric fuel and other energy-related purchases					1

Total commodity	$	54		$	9		$	3		$	117		$	94		$	3

Interest rate⁽³⁾		(1	)		(5	)		42			(72	)		(7	)		(27	)

Total	$	53		$	4		$	45		$	45		$	87		$	(24	)


	Amount of Gain (Loss) Recognized in Income on Derivatives⁽¹⁾												Amount of Gain (Loss) Recognized in Income on Derivatives⁽¹⁾
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives Not Designated as Hedging Instruments	2016			2015			2016			2015			2016			2015			2016			2015
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue	$	(8	)	$	15		$	(6	)	$	18		$	25		$	2		$	19		$	20
Purchased gas		8			(7	)		7			(9	)		(21	)		(3	)		(14	)		(12	)
Electric fuel and other energy-related purchases		(9	)		3			(31	)		9			(12	)		(4	)		(43	)		5
Other operations and maintenance		1			—			—			—
Interest rate⁽²⁾														—			(1	)		—			(1	)

Total	$	(8	)	$	11		$	(30	)	$	18		$	(8	)	$	(6	)	$	(38	)	$	12

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, 2016						December 31, 2015						September 30, 2016						December 31, 2015
	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		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	$	127	$	—	$	127	$	101	$	—	$	101	$	88	$	—	$	88	$	101	$	—	$	101
Interest rate contracts:
Over-the-counter		—		—		—		13		—		13		2		—		2		13		—		13

Total derivatives, subject to a master netting or similar arrangement		127		—		127		114		—		114		90		—		90		114		—		114
Total derivatives, not subject to a master netting or similar arrangement		36		—		36		13		—		13		28		—		28		13		—		13

Total	$	163	$	—	$	163	$	127	$	—	$	127	$	118	$	—	$	118	$	127	$	—	$	127


			June 30, 2016								December 31, 2015								September 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet								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		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	$	127	$	7	$	—	$	120	$	101	$	3	$	—	$	98	$	88	$	2	$	—	$	86	$	101	$	3	$	—	$	98
Interest rate contracts:
Over-the-counter		—		—		—		—		13		10		—		3		2		—		—		2		13		10		—		3

Total	$	127	$	7	$	—	$	120	$	114	$	13	$	—	$	101	$	90	$	2	$	—	$	88	$	114	$	13	$	—	$	101


	June 30, 2016						December 31, 2015						September 30, 2016						December 31, 2015
	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		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)
Commodity contracts:
Over-the-counter	$	14	$	—	$	14	$	5	$	—	$	5	$	9	$	—	$	9	$	5		$	—	$	5
Interest rate contracts:
Over-the-counter		257		—		257		59		—		59		267		—		267		59			—		59

Total derivatives, subject to a master netting or similar arrangement		271		—		271		64		—		64		276		—		276		64			—		64
Total derivatives, not subject to a master netting or similar arrangement		3		—		3		22		—		22		15		—		15		22			—		22

Total	$	274	$	—	$	274	$	86	$	—	$	86	$	291	$	—	$	291	$	86		$	—	$	86


			June 30, 2016								December 31, 2015								September 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet								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		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)
Commodity contracts:
Over-the-counter	$	14	$	7	$	1	$	6	$	5	$	3	$	—	$	2	$	9	$	2	$	—	$	7	$	5	$	3	$	—	$	2
Interest rate contracts:
Over-the-counter		257		—		—		257		59		10		—		49		267		—		—		267		59		10		—		49

Total	$	271	$	7	$	1	$	263	$	64	$	13	$	—	$	51	$	276	$	2	$	—	$	274	$	64	$	13	$	—	$	51

The following table presents the volume of Virginia Power’s derivative activity at ~~June~~September 30, 2016. 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		Current		Noncurrent
Natural Gas (bcf):
Fixed price⁽¹⁾		42		16		32		12
Basis		67		538		126		558
Electricity (MWh):
FTRs		97,710,646		—		70,978,901		—
Interest rate	$	700,000,000	$	1,100,000,000	$	1,200,000,000	$	600,000,000

For the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, gains or losses on hedging instruments determined to be ineffective were not material.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at ~~June~~September 30, 2016:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term		AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Interest rate	$	(21	)	$	(1	)		381 months	$	(22	)	$	(1	)		378 months

Total	$	(21	)	$	(1	)			$	(22	)	$	(1	)

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		Fair Value – Derivatives under Hedge Accounting		Fair Value –Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At June 30, 2016
At September 30, 2016
ASSETS
Current Assets
Commodity	$	—	$	34	$	34	$	—	$	25	$	25
Interest rate								2		—		2

Total current derivative assets⁽¹⁾		—		34		34		2		25		27

Noncurrent Assets
Commodity		—		129		129		—		91		91

Total noncurrent derivative assets⁽²⁾		—		129		129		—		91		91

Total derivative assets	$	—	$	163	$	163	$	2	$	116	$	118

LIABILITIES
Current Liabilities
Commodity	$	—	$	12	$	12	$	—	$	19	$	19
Interest rate		69		—		69		142		—		142

Total current derivative liabilities⁽³⁾		69		12		81		142		19		161

Noncurrent Liabilities
Commodity		—		5		5		—		5		5
Interest rate		188		—		188		125		—		125

Total noncurrent derivatives liabilities⁽⁴⁾		188		5		193		125		5		130

Total derivative liabilities	$	257	$	17	$	274	$	267	$	24	$	291

At December 31, 2015
ASSETS
Current Assets
Commodity	$	—	$	18	$	18	$	—	$	18	$	18

Total current derivative assets⁽¹⁾		—		18		18		—		18		18

Noncurrent Assets
Commodity		—		96		96		—		96		96
Interest rate		13		—		13		13		—		13

Total noncurrent derivative assets⁽²⁾		13		96		109		13		96		109

Total derivative assets	$	13	$	114	$	127	$	13	$	114	$	127

LIABILITIES
Current Liabilities
Commodity	$	—	$	23	$	23	$	—	$	23	$	23
Interest rate		57		—		57		57		—		57

Total current derivative liabilities⁽³⁾		57		23		80		57		23		80

Noncurrent Liabilities
Commodity		—		4		4		—		4		4
Interest rate		2		—		2		2		—		2

Total noncurrent derivative liabilities⁽⁴⁾		2		4		6		2		4		6

Total derivative liabilities	$	59	$	27	$	86	$	59	$	27	$	86

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⁾			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, 2016
Three Months Ended September 30, 2016
Derivative type and location of gains (losses):
Interest rate⁽³⁾	$	(10	)	$	—		$	(108	)	$	(2	)	$	—		$	(16	)

Total	$	(10	)	$	—		$	(108	)	$	(2	)	$	—		$	(16	)

Three Months Ended June 30, 2015
Three Months Ended September 30, 2015
Derivative type and location of gains (losses):
Interest rate⁽³⁾	$	11		$	—		$	91		$	(9	)	$	—		$	(69	)

Total	$	11		$	—		$	91		$	(9	)	$	—		$	(69	)

Six Months Ended June 30, 2016
Nine Months Ended September 30, 2016
Derivative type and location of gains (losses):
Interest rate⁽³⁾	$	(24	)	$	(1	)	$	(241	)	$	(26	)	$	(1	)	$	(258	)

Total	$	(24	)	$	(1	)	$	(241	)	$	(26	)	$	(1	)	$	(258	)

Six Months Ended June 30, 2015
Nine Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Electric fuel and other energy-related purchases				$	(1	)							$	(1	)

Total commodity	$	—		$	(1	)	$	3		$	—		$	(1	)	$	3

Interest rate⁽³⁾		5			—			42			(4	)		—			(27	)

Total	$	5		$	(1	)	$	45		$	(4	)	$	(1	)	$	(24	)


	Amount of Gain (Loss) Recognized in Income on Derivatives⁽¹⁾										Amount of Gain (Loss) Recognized in Income on Derivatives⁽¹⁾
	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives Not Designated as Hedging Instruments	2016			2015		2016			2015		2016			2015			2016			2015
(millions)
Derivative type and location of gains (losses):
Commodity⁽²⁾	$	(10	)	$	5	$	(30	)	$	12	$	(10	)	$	(6	)	$	(40	)	$	6

Total	$	(10	)	$	5	$	(30	)	$	12	$	(10	)	$	(6	)	$	(40	)	$	6

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, 2016						December 31, 2015						September 30, 2016						December 31, 2015
	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		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	$	3	$	—	$	3	$	11	$	—	$	11	$	6	$	—	$	6	$	11	$	—	$	11
Foreign currency contracts:
Over-the-counter														8		—		8		—		—		—

Total derivatives, subject to a master netting or similar arrangement	$	3	$	—	$	3	$	11	$	—	$	11	$	14	$	—	$	14	$	11	$	—	$	11


			June 30, 2016								December 31, 2015								September 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet								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		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	$	3	$	3	$	—	$	—	$	11	$	—	$	—	$	11	$	6	$	1	$	—	$	5	$	11	$	—	$	—	$	11
Foreign currency contracts:
Over-the-counter																		8		4		—		4		—		—		—		—

Total	$	3	$	3	$	—	$	—	$	11	$	—	$	—	$	11	$	14	$	5	$	—	$	9	$	11	$	—	$	—	$	11


	June 30, 2016						December 31, 2015						September 30, 2016						December 31, 2015
	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		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)
Commodity contracts:
Over-the-counter	$	5	$	—	$	5	$	—	$	—	$	—	$	2	$	—	$	2	$	—	$	—	$	—
Interest rate contracts:
Over-the-counter		—		—		—		14		—		14		—		—		—		14		—		14
Foreign currency contracts:
Over-the-counter		7		—		7		—		—		—		4		—		4		—		—		—

Total derivatives, subject to a master netting or similar arrangement	$	12	$	—	$	12	$	14	$	—	$	14	$	6	$	—	$	6	$	14	$	—	$	14


			June 30, 2016								December 31, 2015								September 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet								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		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)
Commodity contracts
Over-the-counter	$	5	$	3	$	—	$	2	$	—	$	—	$	—	$	—	$	2	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Interest rate contracts:
Over-the-counter		—		—		—		—		14		—		—		14		—		—		—		—		14		—		—		14
Foreign currency contracts:
Over-the-counter		7		—		—		7		—		—		—		—		4		4		—		—		—		—		—		—

Total	$	12	$	3	$	—	$	9	$	14	$	—	$	—	$	14	$	6	$	5	$	—	$	1	$	14	$	—	$	—	$	14

The following table presents the volume of Dominion Gas’ derivative activity at ~~June~~September 30, 2016. 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		Current		Noncurrent
Natural Gas (bcf):
Fixed price		7		—		6		—
Basis		7		—		6		—
NGLs (Gal)		52,247,554		—		33,095,554		—
Foreign currency⁽¹⁾	$	—	$	280,000,000	$	—	$	280,000,000

For the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, 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~~September 30, 2016:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 MonthsAfter-Tax			Maximum Term		AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
NGLs	$	(1	)	$	(1	)		9 months	$	(1	)	$	(1	)		6 months
Interest rate		(30	)		(4	)		342 months		(27	)		(2	)		339 months
Foreign currency		(3	)		(3	)		120 months		2			—			117 months

Total	$	(34	)	$	(8	)			$	(26	)	$	(3	)

The following tables present the fair values of Dominion Gas’ 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		Fair Value-Derivatives Under Hedge Accounting		Fair Value-Derivatives Not Under Hedge Accounting		Total Fair Value
(millions)
At June 30, 2016
At September 30, 2016
ASSETS
Current Assets
Commodity	$	2	$	1	$	3	$	1	$	5	$	6

Total current derivative assets⁽¹⁾		2		1		3		1		5		6

Noncurrent Assets
Foreign currency								8		—		8

Total noncurrent derivative assets⁽²⁾								8		—		8

Total derivative assets	$	2	$	1	$	3	$	9	$	5	$	14

LIABILITIES
Current Liabilities
Commodity	$	4	$	1	$	5	$	2	$	—	$	2
Foreign currency		5		—		5		4		—		4

Total current derivative liabilities⁽³⁾		9		1		10		6		—		6

Noncurrent Liabilities
Foreign currency		2		—		2

Total noncurrent derivative liabilities⁽⁴⁾		2		—		2

Total derivative liabilities	$	11	$	1	$	12	$	6	$	—	$	6

At December 31, 2015
ASSETS
Current Assets
Commodity	$	10	$	—	$	10	$	10	$	—	$	10

Total current derivative assets⁽¹⁾		10		—		10		10		—		10

Noncurrent Assets
Commodity		1		—		1		1		—		1

Total noncurrent derivatives assets⁽²⁾		1		—		1		1		—		1

Total derivative assets	$	11	$	—	$	11	$	11	$	—	$	11

LIABILITIES
Noncurrent Liabilities
Interest rate	$	14	$	—	$	14	$	14	$	—	$	14

Total noncurrent derivative liabilities⁽⁴⁾		14		—		14		14		—		14

Total derivative liabilities	$	14	$	—	$	14	$	14	$	—	$	14

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			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, 2016
Three Months Ended September 30, 2016
Derivative Type and Location of Gains (Losses):
Commodity	$	(6	)	$	—
Commodity:
Operating revenue										$	1

Total commodity							$	—		$	1

Interest rate⁽²⁾								—			(1	)
Foreign currency⁽³⁾		(7	)		(2	)		12			3

Total	$	(13	)	$	(2	)	$	12		$	3

Three Months Ended June 30, 2015
Three Months Ended September 30, 2015
Derivative Type and Location of Gains (Losses):
Commodity:
Operating revenue				$	1					$	3

Total commodity	$	—		$	1		$	11		$	3

Interest rate⁽²⁾		4			—			(7	)		—

Total	$	4		$	1		$	4		$	3

Six Months Ended June 30, 2016
Nine Months Ended September 30, 2016
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	4					$	6

Total commodity	$	(7	)	$	4		$	(7	)	$	6

Interest rate⁽²⁾		(9	)		—			(8	)		(2	)
Foreign currency⁽³⁾		(7	)		(2	)		4			1

Total	$	(23	)	$	2		$	(11	)	$	5

Six Months Ended June 30, 2015
Nine Months Ended September 30, 2015
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	1					$	4

Total commodity	$	(2	)	$	1		$	10		$	4

Interest rate⁽²⁾								(8	)		—

Total	$	(2	)	$	1		$	2		$	4


	Amount of Gain (Loss) Recognized in Income on Derivatives										Amount of Gain (Loss) Recognized in Income on Derivatives
	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives Not Designated as Hedging Instruments	2016			2015		2016			2015		2016		2015		2016		2015
(millions)
Derivative Type and Location of Gains (Losses):
Commodity:
Operating revenue	$	(2	)	$	3	$	(2	)	$	4	$	5	$	1	$	3	$	5

Total	$	(2	)	$	3	$	(2	)	$	4	$	5	$	1	$	3	$	5

Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled ~~$104~~$103 million and $100 million at ~~June~~September 30, 2016 and December 31, 2015, respectively.

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			Amortized Cost		Total Unrealized Gains⁽¹⁾		Total Unrealized Losses⁽¹⁾			Fair Value
(millions)
At June 30, 2016
At September 30, 2016
Marketable equity securities:
United States large cap	$	1,326		$	1,251	$	—		$	2,577		$	1,361	$	1,312	$	—		$	2,673
REIT		61			11		—			72			59		8		—			67
Marketable debt securities:
Corporate bonds		474			25		(1	)		498			493		26		(1	)		518
United States Treasury securities and agency debentures		672			26		—			698			645		21		—			666
State and municipal		290			31		—			321			306		27		—			333
Other		108			—		—			108			89		—		—			89
Cost method investments		69			—		—			69			69		—		—			69
Cash equivalents and other⁽²⁾		(12	)		—		—			(12	)		12		—		—			12

Total	$	2,988		$	1,344	$	(1	)⁽³⁾	$	4,331		$	3,034	$	1,394	$	(1	)⁽³⁾	$	4,427

At December 31, 2015
Marketable equity securities:
United States large cap	$	1,295		$	1,213	$	—		$	2,508		$	1,295	$	1,213	$	—		$	2,508
REIT		59			4		—			63			59		4		—			63
Marketable debt securities:
Corporate bonds		433			11		(7	)		437			433		11		(7	)		437
United States Treasury securities and agency debentures		654			8		(4	)		658			654		8		(4	)		658
State and municipal		312			22		—			334			312		22		—			334
Other		99			—		—			99			99		—		—			99
Cost method investments		70			—		—			70			70		—		—			70
Cash equivalents and other⁽²⁾		14			—		—			14			14		—		—			14

Total	$	2,936		$	1,258	$	(11	)⁽³⁾	$	4,183		$	2,936	$	1,258	$	(11	)⁽³⁾	$	4,183

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at ~~June~~September 30, 2016 by contractual maturity is as follows:


	Amount
(millions)
Due in one year or less	$	199
Due after one year through five years		475
Due after five years through ten years		365
Due after ten years		567

Total	$	1,606

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,				Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015		2016		2015		2016		2015
(millions)
Proceeds from sales	$	341	$	243	$	709	$	580	$	300	$	357	$	1,009	$	937
Realized gains⁽¹⁾		37		44		62		100		40		65		102		165
Realized losses⁽¹⁾		15		12		34		29		9		40		43		69

~~Other-than-temporary~~Dominion recorded 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, 2016 and 2015.~~as follows:

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			Amortized Cost		Total Unrealized Gains⁽¹⁾		Total Unrealized Losses⁽¹⁾			Fair Value
(millions)
At June 30, 2016
At September 30, 2016
Marketable equity securities:
United States large cap	$	590		$	546	$	—		$	1,136		$	606	$	576	$	—		$	1,182
REIT		61			11		—			72			59		8		—			67
Marketable debt securities:
Corporate bonds		271			13		(1	)		283			285		13		—			298
United States Treasury securities and agency debentures		270			7		—			277			246		5		—			251
State and municipal		141			17		—			158			158		15		—			173
Other		48			—		—			48			29		—		—			29
Cost method investments		69			—		—			69			69		—		—			69
Cash equivalents and other⁽²⁾		(13	)		—		—			(13	)		5		—		—			5

Total	$	1,437		$	594	$	(1	)⁽³⁾	$	2,030		$	1,457	$	617	$	—	⁽³⁾	$	2,074

At December 31, 2015
Marketable equity securities:
United States large cap	$	574		$	525	$	—		$	1,099		$	574	$	525	$	—		$	1,099
REIT		59			4		—			63			59		4		—			63
Marketable debt securities:
Corporate bonds		237			5		(4	)		238			237		5		(4	)		238
United States Treasury securities and agency debentures		260			1		(2	)		259			260		1		(2	)		259
State and municipal		162			13		(1	)		174			162		13		(1	)		174
Other		34			—		—			34			34		—		—			34
Cost method investments		70			—		—			70			70		—		—			70
Cash equivalents and other⁽²⁾		8			—		—			8			8		—		—			8

Total	$	1,404		$	548	$	(7	)⁽³⁾	$	1,945		$	1,404	$	548	$	(7	)⁽³⁾	$	1,945

The fair value of Virginia Power’s marketable debt securities held in nuclear decommissioning trust funds at ~~June~~September 30, 2016 by contractual maturity is as follows:


	Amount		Amount
(millions)
Due in one year or less	$	71	$	51
Due after one year through five years		207		228
Due after five years through ten years		218		202
Due after ten years		270		270

Total	$	766	$	751

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,				Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015		2016		2015		2016		2015
(millions)
Proceeds from sales	$	154	$	76	$	347	$	209	$	131	$	198	$	478	$	407
Realized gains⁽¹⁾		18		19		30		37		18		45		48		82
Realized losses⁽¹⁾		7		4		17		15		4		18		21		33

Other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds for Virginia Power were not material for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015.

In October 2016, Dominion purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million, which adjusted Dominion’s and Duke’s membership interest to 48% and 47%, respectively.

Dominion Gas’ equity earnings totaled $9$14 million and ~~$12~~$17 million for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, respectively. Dominion Gas received distributions from this investment of ~~$11~~$17 million and ~~$12~~$26 million for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, respectively. At ~~June~~September 30, 2016 and December 31, 2015, the carrying amount of Dominion Gas’ investment of ~~$98~~$97 million and $102 million, respectively, exceeded its share of underlying equity in net assets by $8 million. The difference reflects equity method goodwill and is not being amortized. In May 2016, Dominion Gas sold 0.65% of the non-controlling partnership interest in Iroquois to TransCanada for approximately $7 million, which resulted in a $5 million ($3 million after-tax) ~~gain.~~gain, included in other income in Dominion Gas’ Consolidated Statements of Income.


	June 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
(millions)
Dominion
Regulatory assets:
Deferred rate adjustment clause costs⁽¹⁾	$	95	$	90	$	101	$	90
Deferred nuclear refueling outage costs⁽²⁾		61		75		60		75
Deferred cost of fuel used in electric generation⁽³⁾		5		111		3		111
Other		60		75		86		75

Regulatory assets-current⁽⁴⁾		221		351		250		351

Unrecognized pension and other postretirement benefit costs⁽⁵⁾		992		1,015		981		1,015
Derivatives⁽⁶⁾		351		110		366		110
Deferred rate adjustment clause costs⁽¹⁾		342		295		271		295
PJM transmission rates⁽⁷⁾		192		192		192		192
Income taxes recoverable through future rates⁽⁸⁾		137		126		130		126
Other						203		127

Regulatory assets-non-current						2,143		1,865

Total regulatory assets					$	2,393	$	2,216

Regulatory liabilities:
Deferred cost of fuel used in electric generation⁽³⁾					$	62	$	—
PIPP⁽⁹⁾						26		46
Other						36		54

Regulatory liabilities-current⁽¹⁰⁾						124		100

Provision for future cost of removal and AROs⁽¹¹⁾						1,412		1,120
Nuclear decommissioning trust⁽¹²⁾						882		804
Derivatives⁽⁶⁾						76		79
Deferred cost of fuel used in electric generation⁽³⁾						27		97
Other						200		185

Regulatory liabilities-non-current						2,597		2,285

Total regulatory liabilities					$	2,721	$	2,385

        June 30, 2016         December 31, 2015
(millions)
Other
   136       127




Regulatory assets-non-current
   2,150       1,865




Total regulatory assets
   $ 2,371       $ 2,216




Regulatory liabilities:

Deferred cost of fuel used in electric generation⁽³⁾
   $ 89       $ —
PIPP⁽⁹⁾
   25       46
Other
   47       54




Regulatory liabilities-current⁽¹⁰⁾
   161       100




Provision for future cost of removal and AROs⁽¹¹⁾
   1,148       1,120
Nuclear decommissioning trust⁽¹²⁾
   852       804
Derivatives⁽⁶⁾
   108       79
Deferred cost of fuel used in electric generation⁽³⁾
   26       97
Other
   184       185




Regulatory liabilities-non-current
   2,318       2,285




Total regulatory liabilities
   $ 2,479       $ 2,385




Virginia Power

Regulatory assets:

Deferred rate adjustment clause costs⁽¹⁾
   $ 72       $ 80
Deferred nuclear refueling outage costs⁽²⁾
   61       75
Deferred cost of fuel used in electric generation⁽³⁾
   5       111
Other
   55       60




Regulatory assets-current
   193       326




Derivatives⁽⁶⁾
   351       110
Deferred rate adjustment clause costs⁽¹⁾
   254       213
PJM transmission rates⁽⁷⁾
   192       192
Income taxes recoverable through future rates⁽⁸⁾
   106       97
Other
   63       55




Regulatory assets-non-current
   966       667




Total regulatory assets
   $ 1,159       $ 993




Regulatory liabilities:

Deferred cost of fuel used in electric generation⁽³⁾
   $ 89       $ —
Other
   23       35




Regulatory liabilities-current⁽¹⁰⁾
   112       35




Provision for future cost of removal⁽¹¹⁾
   913       890
Nuclear decommissioning trust⁽¹²⁾
   852       804
Derivatives⁽⁶⁾
   108       79
Deferred cost of fuel used in electric generation⁽³⁾
   26       97
Other
   57       59




Regulatory liabilities-non-current
   1,956       1,929




Total regulatory liabilities
   $ 2,068       $ 1,964




Dominion Gas

Regulatory assets:

Deferred rate adjustment clause costs⁽¹⁾
   $ 23       $ 10
Other
   2       13




Regulatory assets-current⁽⁴⁾
   25       23




Unrecognized pension and other postretirement benefit costs⁽⁵⁾
   277       282
Deferred rate adjustment clause costs⁽¹⁾
   88       82


	June 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
(millions)
Virginia Power
Regulatory assets:
Deferred rate adjustment clause costs⁽¹⁾					$	85	$	80
Deferred nuclear refueling outage costs⁽²⁾						60		75
Deferred cost of fuel used in electric generation⁽³⁾						3		111
Other						49		60

Regulatory assets-current						197		326

Derivatives⁽⁶⁾						366		110
PJM transmission rates⁽⁷⁾						192		192
Deferred rate adjustment clause costs⁽¹⁾						176		213
Income taxes recoverable through future rates⁽⁸⁾						99		97
Other						64		55

Regulatory assets-non-current						897		667

Total regulatory assets					$	1,094	$	993

Regulatory liabilities:
Deferred cost of fuel used in electric generation⁽³⁾					$	62	$	—
Other						13		35

Regulatory liabilities-current						75		35

Provision for future cost of removal⁽¹¹⁾						932		890
Nuclear decommissioning trust⁽¹²⁾						882		804
Derivatives⁽⁶⁾						76		79
Deferred cost of fuel used in electric generation⁽³⁾						27		97
Other						50		59

Regulatory liabilities-non-current						1,967		1,929

Total regulatory liabilities					$	2,042	$	1,964

Dominion Gas
Regulatory assets:
Deferred rate adjustment clause costs⁽¹⁾					$	16	$	10
Other						6		13

Regulatory assets-current⁽⁴⁾						22		23

Unrecognized pension and other postretirement benefit costs⁽⁵⁾						275		282
Deferred rate adjustment clause costs⁽¹⁾						91		82
Income taxes recoverable through future rates⁽⁸⁾		20		20		21		20
Other		66		65		82		65

Regulatory assets-non-current⁽¹³⁾		451		449		469		449

Total regulatory assets	$	476	$	472	$	491	$	472

Regulatory liabilities:
PIPP⁽⁹⁾	$	25	$	46	$	26	$	46
Other		18		9		13		9

Regulatory liabilities-current⁽¹⁰⁾		43		55		39		55

Provision for future cost of removal and AROs⁽¹¹⁾		174		170		173		170
Other		39		31		44		31

Regulatory liabilities-non-current⁽¹⁴⁾		213		201		217		201

Total regulatory liabilities	$	256	$	256	$	256	$	256

(2)	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.

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

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

(5)	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.

(6)	For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

(7)	Reflects amounts related to PJM transmission cost allocation matter. See Note 12 for more information.

(8)

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

(9)	Under PIPP, eligible customers can make reduced payments based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rate adjustment clause according to East Ohio tariff provisions.

(10)	Current regulatory liabilities are presented in other current liabilities in the ~~Companies’~~Dominion’s and Dominion Gas’ 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 assets are presented in other deferred charges and other assets in Dominion Gas’ Consolidated Balance Sheets.

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

At ~~June~~September 30, 2016, ~~$293~~$299 million of Dominion’s, ~~$272~~$234 million of Virginia Power’s and ~~$18~~$23 million of Dominion Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. ~~These~~The majority of these expenditures are expected to be recovered within the next two years.

As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For matters for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum

possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.

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, California and Utah, 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.

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, Old Dominion Electric Cooperative and North Carolina Electric Membership Corporation filed a complaint with FERC against Virginia Power claiming, among other issues, that the incremental costs of undergrounding certain transmission line projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. A settlement of the other issues raised in the complaint was approved by FERC in May 2012.

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 held 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.

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 United States 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 United States 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 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.

In June 2016, PJM, the PJM transmission owners and state commissions representing substantially all of the load in the PJM market submitted a settlement to FERC to resolve the outstanding issues regarding this matter. Under the terms of the settlement, Virginia Power would be required to pay approximately $200 million to PJM over the next 10 years. Although the settlement agreement has not been accepted by FERC, and the settlement is opposed by a small group of parties to the

proceeding, Virginia Power believes it is probable it will be required to make payment as an outcome of the settlement. Accordingly, as of ~~June~~September 30, 2016, Virginia Power has recorded a contingent liability of $200 million in other deferred credits and other liabilities, which is offset by a $192 million regulatory asset for the amount that will be recovered through retail rates in Virginia. The remaining $8 million was recorded in other operations and maintenance expense in the Consolidated Statement of Income for the year ended December 31, 2015.

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, 2015 and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly ~~Report~~Reports on Form 10-Q for the ~~quarter~~quarters ended March 31, ~~2016.~~

In February 2016, certain industrial customers of APCo petitioned the Virginia Commission to issue a declaratory judgment that Virginia legislation enacted in 2015 keeping APCo’s base rates unchanged until at least 2020 (and Virginia Power’s base rates unchanged until at least 2022) is unconstitutional, and to require APCo to make biennial review filings in 2016 and 2018. Virginia Power intervened to support the constitutionality of this legislation. In July 2016, the Virginia Commission held in a divided opinion that this legislation is constitutional, and the industrial customers appealed this order to the Supreme Court of Virginia. This appeal is pending.June 30, 2016.

In May 2016, the Supreme Court of Virginia denied the Attorney General’s unopposed motion to suspend briefing in the previously granted appeals from the Virginia Commission’s orders in Virginia Power’s 2015 biennial review case. The Supreme Court of Virginia later granted leave for the industrial customer appellants to withdraw their appeals, thus concluding this matter.

In May 2016, Virginia Power submitted its annual fuel factor to the Virginia Commission ~~ordered~~to recover an estimated $1.4 billion in Virginia ~~Power’s proposed~~jurisdictional projected fuel expenses for the rate ~~decrease to become effective~~year beginning July 1, ~~2016 on an interim basis.~~2016. Virginia Power’s proposed fuel rate represents a fuel revenue decrease of $286 million when applied to projected kilowatt-hour sales for the period July 1, 2016 to June 30, 2017. ~~This case is pending.~~

In October 2015, Virginia Power filed an application with the Virginia Commission for CPCNs to construct and operate the Scott Solar, Whitehouse, and Woodland solar facilities and related distribution-level interconnection facilities. Virginia Power also applied for approval of Rider US-2 to recover the costs of these projects, which would increase Dominion’s renewable generation by a combined 56 MW at an estimated cost of approximately $130 million, excluding financing costs. In June 2016, the Virginia Commission ~~granted the requested CPCNs and~~ approved ~~a $4 million revenue requirement, subject to true-up on a cost of service basis using a 9.6% ROE for Rider US-2 for the rate year beginning September 1, 2016.~~

~~In August 2016,~~ Virginia Power filed an application with the Virginia Commission for a CPCN to construct and operate the Oceana solar facility and related distribution interconnection facilities on land owned by the United States Navy. The facility would begin commercial operations in late 2017 and increase Dominion’s renewable generation by approximately 18 MW at an estimated cost of approximately $40 million, excluding financing costs. The facility is the subject of a public-private partnership whereby the Commonwealth of Virginia, a non-jurisdictional customer, will compensate Virginia Power for the facility’s net electrical energy output. Virginia Power will retire renewable energy certificates on the Commonwealth’s behalf in an amount equal to those generated by the facility. There is no rate adjustment clause associated with this CPCN filing, nor will any costs of the project be recovered from jurisdictional customers. This case is pending.Power’s proposed fuel rate.

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

Virginia Power previously filed an application with the Virginia Commission for a ~~$1 million increase over~~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 ~~revenues projected to be produced during~~existing 230 kV Loudoun-Brambleton line and the ~~rate year under current rates.~~Poland Road substation. In ~~July~~August 2016, the Virginia Commission ~~approved Virginia Power’s proposed total revenue requirement.~~granted a CPCN to construct and operate the project along a revised route.

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna nuclear power station. 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 in 2017. Virginia Power has not yet committed to building a new nuclear unit at North Anna nuclear power station.

~~The motions and petitions filed~~Requests by BREDL ~~prior to April 2015 were~~for a contested NRC hearing on Virginia Power’s COL application have been dismissed, and ~~under a previous ruling~~in September 2016, the United States Court of Appeals for the ~~NRC, the contested portion~~District of ~~the COL proceeding remains terminated. The NRC is required to conduct a hearing in all COL proceedings,~~Columbia dismissed with prejudice petitions for judicial review that BREDL and ~~if a new contention is not admitted, the mandatory NRC hearing will be uncontested.~~

~~In April 2015, BREDL~~other organizations had filed ~~a new motion and petition~~ challenging the NRC’s reliance on ~~its~~a rule generically assessing the environmental impacts of continued onsite storage of spent nuclear fuel in licensing proceedings. The BREDL filings were 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 August 2015, BREDL filed a petition in the United States Court of Appeals for the District of Columbia Circuit seeking review of the NRC’s June 2015 decision, and Virginia Power intervened. This petition and nine similar petitions relating to other NRCvarious licensing proceedings, ~~were held in abeyance pending~~including Virginia Power’s COL proceeding. This dismissal followed the ~~outcome of the ongoing judicial review of the NRC’s continued storage rule before the same court. In~~Court’s June 2016 decision inNew York v. NRC, ~~the court upheld~~upholding the NRC’s continued storage ~~rule. In July~~rule and August 2016 ~~the petitioners in~~~~New York v. NRC~~ ~~petitioned~~denial of requests for rehearing en ~~banc~~banc. Therefore, the contested portion of the COL proceeding is closed. The NRC is required to conduct a hearing in all COL proceedings. This mandatory NRC hearing will be uncontested.

In August 2016, Virginia Power received a 60-day notice of intent to sue from the Sierra Club alleging Endangered Species Act violations. The notice alleges that the United States Army Corps of Engineers failed to conduct adequate environmental and consultation reviews, related to a potential third nuclear unit located at North Anna, prior to issuing a CWA section 404 permit to Virginia Power in September 2011. Virginia Power is currently unable to make an estimate of the potential impacts to its consolidated financial statements related to this matter.

In March 2016, Virginia Power filed its base rate case and schedules with the North Carolina Commission. Virginia Power proposed a non-fuel, base rate increase of $51 million effective November 1, 2016 with an ROE of 10.5%. In October 2016, Virginia Power entered into a stipulation and settlement agreement for a non-fuel, base rate increase of $35 million with an ROE of 9.9% effective November 1, 2016, on ~~their challenge~~a temporary basis subject to refund, with any permanent rates ordered by the North Carolina Commission effective January 1, 2017. This case is pending.

In August 2016, Virginia Power submitted its annual filing to the ~~continued storage rule, and~~North Carolina Commission to adjust the ~~court ordered that BREDL’s August 2015 petition pertaining~~fuel component of its electric rates. Virginia Power proposed a total $36 million decrease to the ~~application~~fuel component of ~~this rule to North Anna 3, and~~its electric rates for the ~~similar petitions relating to other NRC proceedings, continue to be held in abeyance until the court’s disposition of the rehearing petition.~~rate year beginning January 1, 2017. This case is pending.

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 2016, 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 recovery over the twelve-month period from July 2016 through June 2017 of projected deferred program costs of approximately $32 million from April 2016 through June 2017, net of a refund for over-recovery of accumulated arrearages of approximately $28 million as of March 31, 2016.

2008, East Ohio ~~has approval for a UEX Rider through which it recovers the bad debt expense~~began PIR, aimed at replacing approximately 25% 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.~~its pipeline system. In ~~May 2016,~~March 2015, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years and to increase the annual capital investment, with corresponding increases in the annual rate-increase caps. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to settle East Ohio’s pending application. As requested, the PIR Program and associated cost recovery will continue for another five-year term, calendar years 2017 through 2021, and East Ohio will be permitted to increase its ~~UEX Rider~~annual capital expenditures to ~~reflect a refund~~$200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio. Costs associated with calendar year 2016 investment will be recovered under the existing terms.

In November 2016, the Ohio Commission approved East Ohio’s request to defer the operation and maintenance costs associated with implementing PSMP of ~~over-recovered accumulated bad debt expense of approximately $8~~up to $15 million ~~as of March 31, 2016, and recovery of prospective net bad debt expense projected to total approximately $19 million for the twelve-month period from April 2016 to March 2017. This case is pending.~~per year.

In May 2016, Hope filed a PREP application with the West Virginia Commission requesting approval of a projected capital investment for 2017 of $27 million as part of a total five-year projected capital investment of $152 million. ~~The~~In September 2016, Hope reached a settlement with all parties to the case agreeing to new PREP customer rates, ~~would be effective~~for the year beginning November 1, ~~2016. This case is pending.~~2016, that provide for projected revenue of $2 million related to capital investments of $20 million and $27 million for 2016 and 2017, respectively. In October 2016, the West Virginia Commission approved the settlement.

In ~~June~~August 2016, ~~DCG~~Dominion Gas received FERC authorization to construct and operate the ~~approximately $45 million Columbia to Eastover~~Leidy South Project ~~facilities, which are~~facilities. Service under the 20-year contracts is expected to ~~be placed into service~~commence in the fourth quarter of ~~2016.~~2017. The project is expected to cost approximately $210 million and provide 155,000 Dths per day of firm transportation service from Clinton County, Pennsylvania to Loudoun County, Virginia.

The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both: 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.

As of September 30, 2016, Dominion owns the general partner interest and ~~64.8%~~65.0% of the limited partnership interests in Dominion Midstream, which owns a preferred equity interest and the general partner interest in Cove Point. Additionally, Dominion owns the manager and 67% of the membership interest in certain merchant solar facilities, as discussed in Note 2. Dominion has concluded that these entities are VIEs due to the limited partners or members lacking the characteristics of a controlling financial interest. Dominion is the primary beneficiary of Dominion Midstream and the merchant solar facilities, and Dominion Midstream is the primary beneficiary of Cove Point, as they have the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them.

Dominion ~~has an initial 45%~~owns a 48% membership interest in Atlantic Coast Pipeline. Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, which is expected to be in service in the second half of 2019. See Note 9 to the Companies’ Annual Report on Form 10-K for the year ended

December 31, 2015 for more details regarding the nature of this entity. Dominion concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion has concluded that it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. Dominion is obligated to provide capital contributions based on its ownership percentage. Dominion’s maximum exposure to loss is limited to its current and future investment.

Dominion and Virginia Power’s nuclear decommissioning trust funds and Dominion’s rabbi trusts hold investments in limited partnerships or similar type entities (see Note 10 for further details). Dominion and Virginia Power concluded that these partnership investments are VIEs due to the limited partners lacking the characteristics of a controlling financial interest. Dominion and Virginia Power have concluded neither is the primary beneficiary as they do not have the power to direct the activities that most significantly impact these VIEs’ economic performance. Dominion and Virginia Power are obligated to provide capital contributions to the partnerships as required by each partnership agreement based on their ownership percentages. Dominion and Virginia Power’s maximum exposure to loss is limited to their current and future investments.

Dominion previously concluded that Iroquois was a VIE because a non-affiliated Iroquois equity holder had the ability during a limited period of time to transfer its ownership interests to another Iroquois equity holder or its affiliate. At the end of the first quarter of 2016, such right no longer existed and, as a result, Dominion concluded that Iroquois is no longer a VIE.

Virginia Power had long-term power and capacity contracts with five non-utility generators; however, contracts with two of these generators expired in 2015, leaving three non-utility generators with an aggregate summer generation capacity of approximately 418 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 2017 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled ~~$357~~$320 million as of ~~June~~September 30, 2016. Virginia Power paid $37 million and ~~$55~~$52 million for electric capacity and $5$11 million and ~~$23 million for electric energy to these entities in the~~

~~three months ended June 30, 2016 and 2015, respectively. Virginia Power paid $74 million and $108 million for electric capacity and $12 million and $60~~$17 million for electric energy to these entities in the ~~six~~three months ended ~~June~~September 30, 2016 and 2015, respectively. Virginia Power paid $111 million and $160 million for electric capacity and $23 million and $77 million for electric energy to these entities in the nine months ended September 30, 2016 and 2015, respectively.

DTI has been engaged to oversee the construction of, and to subsequently operate and maintain, the projects undertaken by Atlantic Coast Pipeline based on the overall direction and oversight of Atlantic Coast Pipeline’s members. An affiliate of DTI holds a membership interest in Atlantic Coast Pipeline, therefore DTI is considered to have a variable interest in Atlantic Coast Pipeline. The members of Atlantic Coast Pipeline hold the power to direct the construction, operations and maintenance activities of the entity. DTI has concluded it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance. DTI has no obligation to absorb any losses of the VIE. See Note 17 for information about associated related party receivable balances.

Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of ~~$74~~$80 million and ~~$29~~$31 million for the three months ended ~~June~~September 30, 2016, ~~$83~~$73 million and ~~$30~~$27 million for the three months ended ~~June~~September 30, 2015, ~~$188~~$268 million and ~~$64~~$95 million for the ~~six~~nine months ended ~~June~~September 30, 2016 and ~~$166~~$239 million and ~~$58~~$85 million for the ~~six~~nine months ended ~~June~~September 30, 2015, respectively. Virginia Power and Dominion Gas determined that neither is the primary beneficiary of DRS as neither has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it. 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.

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.

At ~~June~~September 30, 2016, 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		Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility⁽¹⁾	$	5,000	$	3,437	$	—	$	1,563	$	5,000	$	3,073	$	—	$	1,927
Joint revolving credit facility⁽¹⁾		500		—		52		448		500		—		60		440
Revolving multi-year credit facility⁽²⁾										500		24		—		476
Revolving 364-day credit facility⁽²⁾										250		—		—		250

Total	$	5,500	$	3,437	$	52	$	2,011	$	6,250	$	3,097	$	60	$	3,093

Virginia Power’s short-term financing is supported through its access as co-borrower to the two joint revolving credit facilities. These credit facilities can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

At ~~June~~September 30, 2016, Virginia Power’s share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion and Dominion Gas, were as follows:


	Facility Limit⁽¹⁾		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Limit⁽¹⁾		Outstanding Commercial Paper		Outstanding Letters of Credit
(millions)
Joint revolving credit facility⁽¹⁾	$	5,000	$	1,423	$	—	$	5,000	$	965	$	—
Joint revolving credit facility⁽¹⁾		500		—		—		500		—		—

Total	$	5,500	$	1,423	$	—	$	5,500	$	965	$	—

In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility. In May 2016, the maturity date for this facility was extended from April 2019 to April 2020. As of ~~June~~September 30, 2016, this facility supports ~~$119~~$100 million of certain variable rate tax-exempt financings of Virginia Power. In October 2016, this facility was reduced from $120 million to $100 million.

Dominion Gas’ short-term financing is supported by its access as co-borrower to the two joint revolving credit facilities. These credit facilities can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

At ~~June~~September 30, 2016, Dominion Gas’ share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion and Virginia Power were as follows:


	Facility Limit⁽¹⁾		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Limit⁽¹⁾		Outstanding Commercial Paper		Outstanding Letters of Credit
(millions)
Joint revolving credit facility⁽¹⁾	$	1,000	$	238	$	—	$	1,000	$	60	$	—
Joint revolving credit facility⁽¹⁾		500		—		—		500		—		—

Total	$	1,500	$	238	$	—	$	1,500	$	60	$	—

In March 2016 and May 2016, Dominion successfully remarketed the $550 million 2013 Series A 1.07% RSNs due 2021 and the $550 million 2013 Series B 1.18% RSNs due 2019, respectively, pursuant to the terms of the related 2013 Equity Units. In connection with the remarketings, the interest rate on the Series A and Series B junior subordinated notes was reset to 4.104% and 2.962%, respectively, payable on a semi-annual basis and Dominion ceased to have the ability to redeem the notes at its option or defer interest payments. At ~~June~~September 30, 2016, the securities are included in junior subordinated notes in Dominion’s Consolidated Balance Sheets. Dominion did not receive any proceeds from the remarketings. Remarketing proceeds belonged to the investors holding the related 2013 Equity Units and were temporarily used to purchase a portfolio of treasury securities. Upon maturity of each portfolio, the proceeds were applied on behalf of investors on the related stock purchase contract settlement date to pay the purchase price to Dominion for issuance of 8.5 million shares of its common stock on both April 1, 2016 and July 1, 2016. See Issuance of Common Stock below for a description of common stock issued by Dominion in April 2016 and July 2016 under the stock purchase contracts.

In August 2016, Dominion issued $1.4 billion of 2016 Equity Units, initially in the form of 2016 Series A Corporate Units. The Corporate Units are listed on the NYSE under the symbol DCUD. The net proceeds were used to finance the Dominion Questar Combination. See Note 3 for more information.

Each 2016 Series A Corporate Unit consists of a stock purchase contract, a 1/40 interest in a 2016 Series A-1 RSN issued by Dominion and a 1/40 interest in a 2016 Series A-2 RSN issued by Dominion. The stock purchase contracts obligate the holders to purchase shares of Dominion common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is $50 per Corporate Unit and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion common stock near the settlement date. The RSNs are pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.

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

Dominion has recorded the present value of the stock purchase contract payments as a liability offset by a charge to equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, Dominion applies the treasury stock method to the 2016 Equity Units. These securities did not have an effect on diluted EPS for the three and nine months ended September 30, 2016.

Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion will issue between 15.0 million and 18.7 million shares of its common stock in August 2019. A total of 23.1 million shares of Dominion’s common stock has been reserved for issuance in connection with the stock purchase contracts.

In the first quarter of 2016, Dominion purchased and cancelled $38 million and $4 million of the June 2006 hybrids and the September 2006 hybrids, respectively.

In July 2016, Dominion launched a tender offer to purchase up to $200 million in aggregate of additional June 2006 hybrids and September 2006 hybrids, which expired on August 1, 2016. In connection with the tender offer, Dominion purchased and cancelled $125 million and $74 million of the June 2006 hybrids and the September 2006 hybrids, respectively. All purchases were conducted in compliance with the applicable replacement capital covenants. Also in July 2016, Dominion issued $800 million of 5.25% July 2016 hybrids. The proceeds were used for general corporate purposes, including to finance the tender offer. The July 2016 hybrids are listed on the ~~New York Stock Exchange~~NYSE under the symbol DRUA.

From time to time, Dominion may reduce its outstanding debt and level of interest expense through redemption of debt securities prior to maturity and repurchases in the open market, in privately negotiated transactions, through additional tender offers or otherwise.

In May 2016, Dominion Gas issued $150 million of private placement 3.8% ~~Senior Notes~~senior notes that mature in 2031. In June 2016, Dominion Gas issued $250 million of private placement 2.875% ~~Senior Notes~~senior notes that mature in 2023. Also in June 2016, Dominion Gas issued €250 million of private placement 1.45% ~~Senior Notes~~senior notes that mature in 2026. The notes were recorded at $280 million at issuance and included in long-term debt in the Consolidated Balance Sheets at ~~$278~~$281 million at ~~June~~September 30, 2016.

In August 2016, Dominion issued $500 million of 1.60% senior notes, $400 million of 2.0% senior notes and $400 million of 2.85% senior notes that mature in 2019, 2021 and 2026, respectively. The net proceeds were used to finance the Dominion Questar Combination. See Note 3 for more information.

In September 2016, Dominion issued $300 million of private placement 1.50% senior notes that mature in 2018.

In September 2016, Dominion borrowed $1.2 billion under a private placement term loan agreement that matures in September 2017 and bears interest at a variable rate. The net proceeds were used to finance the Dominion Questar Combination. See Note 3 for more information. In November 2016, Dominion Midstream completed the issuance and public offering of common units for net proceeds of $348 million. Accordingly, $348 million of the borrowings under the private placement term loan are included in long-term debt in Dominion’s Consolidated Balance Sheets.

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 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 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 ~~New York Stock Exchange~~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. Following issuances during the first and second quarters of 2015, Dominion has the ability to issue up to approximately $200 million of stock under the 2014 sales agency agreements; however, no additional issuances have occurred under these agreements in 2016.

In both April 2016 and July 2016, Dominion issued 8.5 million shares under the related stock purchase contract entered into as part of Dominion’s 2013 Equity Units. Additionally, Dominion completed a market issuance of equity in April 2016 of 10.2 million shares and ~~receipt of~~received proceeds of $756 million through a registered underwritten public offering. ~~In connection with receipt~~A portion of ~~these~~the net proceeds was used to finance the ~~acquisition financing commitments~~Dominion Questar Combination. See Note 3 for ~~the Questar Combination were reduced from $3.9 billion to $3.14 billion in April 2016.~~more information.

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.

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.

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 power station to defer planned retirements and allow for continued operation of the units to address reliability concerns while necessary electric transmission upgrades are being completed. These coal units will need to continue operating until at least April 2017 due to delays in transmission upgrades needed to maintain electric ~~reliability, which based on assumptions about the timing for required agency actions and construction schedules are expected to be completed by no earlier than the second quarter of 2017.~~reliability. Therefore, in October 2015, Virginia Power submitted a request to the EPA for an additional one year compliance extension under an EPA Administrative Order. The order was signed by the EPA in April 2016 allowing the Yorktown power station units to operate for up to one additional year, as required to maintain reliable power availability while transmission upgrades are being made.

In June 2015, the United States 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 United States Court of Appeals for the District of Columbia Circuit. However, the Supreme Court did not vacate or stay the effective date and implementation of the MATS rule. In November 2015, in response to the Supreme Court decision, the EPA proposed a supplemental finding that consideration of cost does not alter the agency’s previous conclusion that it is appropriate and necessary to regulate coal- and oil-fired electric utility steam generating units under Section 112 of the CAA. In December 2015, the District of Columbia Court of Appeals issued an order remanding the MATS rulemaking proceeding back to the EPA without setting aside judgment, noting that EPA had represented it was on track to issue a final finding regarding its consideration of cost. In April 2016, the EPA issued a final supplemental finding that consideration of costs does not alter its

conclusion regarding appropriateness and necessity for the regulation. These actions do not change Virginia Power’s plans to close coal units at Yorktown power station by April 2017 or the need to complete necessary electricity transmission upgrades ~~by 2017.~~which are expected to be in service approximately 20 months following receipt of all required permits and approvals for construction. Since the MATS rule remains in effect and Dominion is complying with the requirements of the rule, Dominion does not expect any adverse impacts to its operations at this time.

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

Following numerous petitions by industry participants for review and a successful motion for stay, in October 2014, the United States Court of Appeals for the District of Columbia 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~~applied in 2015 and 2016, and Phase 2 emissions budgets will apply in 2017 and beyond. CSAPR replaced CAIR beginning in January 2015. In September 2016, the EPA issued a revision to CSAPR that reduces the ozone season NO_X emission budgets in 22 states beginning in 2017. The cost to comply with CSAPR, including the recent revision to the CSAPR ozone season NOx program, is not expected to be material to Dominion’s or Virginia Power’s Consolidated Financial Statements. ~~Future outcomes of any additional litigation and/or any action to issue a revised rule, including the EPA’s recent proposal to reduce the ozone season NO~~_X ~~emission budgets beginning in 2017, could affect the assessment regarding cost of compliance.~~

In October 2015, the EPA issued a final rule tightening the ozone standard, set in 2008, from 75-ppb to 70-ppb. To comply with the 2008 standard, in April 2016 Virginia Power submitted the NO_X Reasonable Available Control Technology analysis for Unit 5 at Possum Point power station. The EPA is expected to complete attainment designations for a new standard by December 2017 and states will have until 2020 or 2021 to develop plans to address the new standard. ~~To comply with the 2008 standard, in April 2016 Dominion submitted the NO~~_X ~~Reasonable Available Control Technology analysis for Unit 5 at Possum Point power station.~~ 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 April 2014, the Pennsylvania Department of Environmental Protection issued proposed regulations to reduce NO_X and VOC emissions from combustion sources. The regulations were finalized in April 2016. To comply with the regulations, Dominion Gas anticipates installing emission control systems on existing engines at several compressor stations in Pennsylvania. The compliance costs associated with engineering and installation of controls and compliance demonstration with the regulation are expected to be approximately $25 million.

In August 2012, the EPA issued the first NSPS impacting new and modified facilities in 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 VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In September 2015, the EPA issued a proposed NSPS (for the oil and natural gas sector) to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. The proposed regulation was finalized in June 2016. All projects which commenced construction after September 2015 will be required to comply with this regulation. Dominion and Dominion Gas are implementing the final regulation. Dominion ~~currently estimates the potential impacts on results of operations, financial condition and/or cash flows related to this matter to be immaterial.~~and Dominion Gas isare still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.

In January 2015, as part of its Climate Action Plan, the EPA announced plans to reduce methane emissions from the oil and gas sector including natural gas processing and transmission sources. In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR program, the Natural Gas STAR Methane Challenge Program. The proposed program covers the entire natural gas sector from production to distribution, with more emphasis on transparency and increased reporting for both annual emissions and reductions achieved through implementation measures. In March 2016, Dominion and Dominion Questar

joined the EPA as a founding ~~partner~~partners in this program for its distribution companies, East Ohio and Hope, DTI and ~~DTI.~~Questar Gas. In September 2016, Dominion and Dominion Questar, prior to the Dominion Questar Combination, submitted implementation plans for participation in the Methane Challenge Program to the EPA.

In March 2016, as part of ~~President Obama’s~~its Climate Action Plan, the EPA began development of regulations for reducing methane emissions from existing sources in the oil and natural gas sectors. In June 2016 and September 2016, the EPA issued a draft Information Collection Request to collect information on existing sources upstream of distribution in this sector. The final Information Collection Request is expected in the fourth quarter of 2016. Depending on the results of this Information Collection Request effort, the EPA may propose new regulations on existing sources. Dominion and Dominion Gas cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.

In October 2013, the United States Supreme Court granted petitions filed by several industry groups, states, and the United States Chamber of Commerce seeking review of the United States Court of Appeals for the District of Columbia Circuit’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 United States 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~~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 August 2015, the EPA published a final rule rescinding the requirement for all new and modified major sources to obtain permits based solely on their GHG emissions. 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~~In August 2016, the EPA issued a draft rule proposing to ~~uncertainty regarding what additional actions states may take~~reaffirm that a source’s obligation to ~~amend their existing regulations~~obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and ~~what action~~to set a significant emissions rate at 75,000 tons per year of CO₂ equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes ~~to address the Court ruling under a new~~final action on this rulemaking, the Companies cannot predict the impact to their financial ~~statements at this time.~~statements.

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 United States Court of Appeals for the District of Columbia 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.

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 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 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule establishes updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. Virginia Power has eight facilities that may be subject to additional wastewater treatment requirements associated with the final rule. The expenditures to comply with these new requirements are expected to be material.

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 United States 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 United States 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~~The Companies do not believe ~~this~~these matters 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, pursuant to CERCLA, 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~~In September 2016, the United States, on behalf of the EPA, lodged a ~~liable party under CERCLA based on its alleged connection~~proposed Remedial Design/Remedial Action Consent Decree with the United States District Court for the Eastern District of North Carolina, settling claims related to the ~~site. In November 2011, Virginia Power~~site between the EPA and a number of ~~other~~ parties, ~~notified~~including Virginia Power. The Consent Decree identifies Virginia Power as a non-performing cash-out party to the ~~EPA that they are declining~~settlement and, once approved by the court, would resolve Virginia Power’s alleged liability under CERCLA with respect to ~~undertake~~ the ~~work set forth in~~site, including liability pursuant to the UAO.

The ~~EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery~~ultimate outcome of ~~its costs in undertaking removal or remedial action. If~~this matter depends on the ~~court determines that a respondent failed to comply with~~approval of 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~~Consent Decree by the ~~EPA as~~Court, and cannot be predicted at this time; however, this matter is not expected to have a ~~result of the party’s failure to comply with the UAO.~~material effect on Virginia ~~Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter.~~Power.

Dominion has determined that it is associated with 1719 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.

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.

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 United States District Court for the 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. In July 2015, the contractor filed a complaint against DTI in United States District Court for the Western District of Pennsylvania. In August 2015, DTI filed a motion to dismiss, or in the alternative, a motion to transfer venue to Virginia. In March 2016, the Pennsylvania court granted the motion to dismiss and transferred the case to the United States District Court for the Eastern District of Virginia. In April 2016, the Virginia court issued an order staying the proceedings and ordering mediation. A mediation occurred in May 2016 but was unsuccessful. In July 2016, DTI filed a motion to dismiss. This case is pending. DTI has accrued a liability of $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.

In connection with the Appalachian Gateway project, Dominion Field Services, Inc. entered into contracts for firm purchase rights with a group of small gas producers. In June 2016, the gas producers filed a complaint in the Circuit Court of Marshall County, West Virginia against Dominion, DTI and Dominion Field Services, Inc., among other defendants, claiming that the contracts are unenforceable and seeking compensatory and punitive damages. During the third quarter of 2016, Dominion, DTI and Dominion Field Services, Inc. were served with the complaint. Also in the third quarter of 2016, Dominion and DTI, with the consent of the other defendants, removed the case to the United States District Court for the Northern District of West Virginia. In October 2016, the defendants filed a motion to dismiss. This case is pending. Dominion and Dominion Gas cannot currently estimate financial statement impacts, but there could be a material impact to their financial condition and/or cash flows.

In September 2014, Virginia Power received a notice from the Southern Environmental Law Center on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at Possum Point power station. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point power station’s historical and active ash storage facilities. A similar notice from the Southern Environmental Law Center on behalf of the Sierra Club was subsequently received related to Chesapeake power station. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum Point power station, Chesapeake and Bremo power stations as settlement of the potential litigation. While the issue is open to potential further negotiations, the Southern Environmental Law Center 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 power station. Virginia Power filed a motion to dismiss in April 2015, which was denied in November 2015. A trial was held in June 2016. This case is pending. As a result of the December 2014 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 time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary. In April 2016, the EPA announced a partial settlement with certain environmental and industry organizations that had challenged the final CCR rule in the United States Court of Appeals for the District of Columbia Circuit. As part of the settlement, certain exemptions included in the final rule for inactive ponds that closed by April 2018 will be removed, resulting in inactive ponds ultimately being subject to the same requirements as existing ponds. In June 2016, the court issued an order approving the settlement, which requires the EPA to modify provisions in the final CCR rule concerning inactive ponds. In August 2016, the EPA issued a final rule, effective October 2016, extending certain compliance deadlines in the final CCR rule for inactive ponds. Virginia Power does not believe ~~this change~~these changes will substantially impact its closure plans for inactive ponds.

In 2015, Virginia Power recorded a $386 million ARO related to future ash pond and landfill closure costs. Recognition of the ARO also resulted in a $99 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $166 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. Virginia Power is in the process of

obtaining the necessary permits to complete the work. In February and March 2016, respectively, two parties filed administrative appeals in the Circuit Court for the City of Richmond challenging certain provisions, relating to ash pond dewatering activities, of Possum Point power station’s wastewater discharge permit issued by the VDEQ in January 2016. One of those parties withdrew its appeal in June 2016. ~~Virginia Power cannot predict~~In November 2016, the ~~financial impact associated with~~court dismissed the remaining ~~appeal, but believes that it will not be material.~~appeal. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the increased obligation in 2015.

Dominion is constructing the Liquefaction Project at the Cove Point facility, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project. In October 2014, several parties filed a motion with FERC to stay the order and requested rehearing. In May 2015, FERC denied the requests for stay and rehearing.

Two parties have separately filed petitions for review of the FERC order in the United States Court of Appeals for the District of Columbia Circuit, which petitions ~~have been~~were consolidated. Separately, one party requested a stay of the FERC order until the judicial proceedings are complete, which the court denied in June 2015.

In July 2016, the court denied one party’s petition for review of the FERC order authorizing the Liquefaction Project. The court also issued a decision remanding the other party’s petition for review of the FERC order to FERC for further explanation of FERC’s decision that a previous transaction with an existing import shipper was not unduly discriminatory. Cove Point believes that on remand FERC will be able to justify its decision.

In September 2013, the DOE granted Non-FTA Authorization approval for the export of up to 0.77 bcfe/day of natural gas to countries that do not have an FTA for trade in natural gas. In June 2016, a party filed a petition for review of this approval in the United States Court of Appeals for the District of Columbia Circuit. This case is pending.

The FERC staff in the Office of Enforcement, Division of Investigations, is conducting a non-public investigation of Virginia Power’s offers of combustion turbines generators into the PJM day-ahead markets from April 2010 through September 2014. The FERC staff notified Virginia Power of its preliminary findings relating to Virginia Power’s alleged violation of FERC’s rules in connection with these activities. Virginia Power has provided its response to the FERC staff’s preliminary findings letter explaining why Virginia Power’s conduct was lawful and refuting any allegation of wrongdoing. Virginia Power is cooperating fully with the investigation; however, it cannot currently predict whether or to what extent it may incur a material liability.

Virginia Power is constructing Greensville County and related transmission interconnection facilities. In July 2016, the Sierra Club filed an administrative appeal in the Circuit Court for the City of Richmond challenging certain provisions in Greensville County’s PSD air permit issued by VDEQ in June 2016. Virginia Power is currently unable to make an estimate of the potential impacts to its consolidated financial statements related to this matter.

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 the Institute of Nuclear Power Operations. Like other United States 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 requiring 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 have been implemented. The information requests issued by the NRC request each reactor to reevaluate the seismic and external flooding hazards at their site using present-day methods and information, conduct

walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. The walkdowns of each unit have been completed, audited by the NRC

and found to be adequate. Reevaluation of the emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevaluation of the seismic and external flooding hazards is expected to continue through 2018. Dominion and Virginia Power do not currently expect that compliance with the NRC’s information requests will materially impact their financial position, results of operations or cash flows during the implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion and Virginia Power do not expect material financial impacts related to compliance with Tier 2 and Tier 3 recommendations.

At ~~June~~September 30, 2016, Dominion had issued $73 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of ~~June~~September 30, 2016, Dominion’s exposure under these guarantees was $43 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.

At ~~June~~September 30, 2016, Dominion had issued the following subsidiary guarantees:


	Stated Limit		Value⁽¹⁾		Stated Limit		Value⁽¹⁾
(millions)
Subsidiary debt⁽²⁾	$	27	$	27	$	27	$	27
Commodity transactions⁽³⁾		2,074		864		2,081		874
Nuclear obligations⁽⁴⁾		189		81		169		94
Cove Point⁽⁵⁾		1,900		—		1,900		—
Solar⁽⁶⁾		1,514		244		1,847		539
Other⁽⁷⁾		420		28		783		60

Total	$	6,124	$	1,244	$	6,807	$	1,594

Additionally, at ~~June~~September 30, 2016, Dominion had purchased ~~$120~~$147 million of surety bonds, including ~~$69~~$70 million at Virginia Power and $21 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of ~~$52~~$60 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.

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, 2015.

At ~~June~~September 30, 2016, Dominion’s credit exposure related to energy marketing and price risk management activities totaled ~~$111~~$96 million. Of this amount, investment grade counterparties, including those internally rated, represented ~~88%~~70%. No single counterparty, whether investment grade or non-investment grade, exceeded ~~$31~~$21 million of exposure. At September 30, 2016, Virginia Power’s exposure related to sales to wholesale customers totaled $23 million. Of this amount, investment grade counterparties, including those internally rated, represented 35%. No single counterparty, whether investment grade or non-investment grade, exceeded $4 million of exposure.

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~~September 30, 2016 and December 31, 2015, Dominion would have been required to post an additional $4$7 million and $12 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 not posted any collateral at ~~June~~September 30, 2016 or December 31, 2015 related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of ~~June~~September 30, 2016 and December 31, 2015 was ~~$13~~$18 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~~September 30, 2016 and December 31, 2015. See Note 9 for further information about derivative instruments.

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. Dominion’s transactions with equity method investments are described in Note 10. A discussion of significant related-party transactions follows.

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 physical forwards and options, to manage commodity price risks associated with purchases of natural gas. As of ~~June~~September 30, 2016, Virginia Power’s derivative assets and liabilities with affiliates were ~~each $36~~$28 million and $3$15 million, respectively. As of December 31, 2015, Virginia Power’s derivative assets and liabilities with affiliates were $13 million and $22 million, respectively. See Note 9 for more information.

Virginia Power participates in certain Dominion benefit plans described in Note 18. In Virginia Power’s Consolidated Balance Sheets at ~~June~~September 30, 2016 and December 31, 2015, amounts due to Dominion associated with these benefit plans included in other deferred credits and other liabilities were ~~$356~~$376 million and $316 million, respectively, and amounts due from Dominion at ~~June~~September 30, 2016 and December 31, 2015 included in other deferred charges and other assets were ~~$98~~$111 million and $77 million, respectively.

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,				Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015		2016		2015		2016		2015
(millions)
Commodity purchases from affiliates	$	99	$	94	$	244	$	346	$	172	$	123	$	416	$	469
Services provided by affiliates⁽¹⁾		102		107		242		217		105		96		347		313
Services provided to affiliates		7		5		12		10		5		5		17		15

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~~September 30, 2016. There were $376 million in short-term demand note borrowings from Dominion as of December 31, 2015. Virginia Power had no outstanding borrowings under the Dominion money pool for its nonregulated subsidiaries as of ~~June~~September 30, 2016 and December 31, 2015. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015.

There were no issuances of Virginia Power’s common stock to Dominion for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015.

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~~September 30, 2016 and December 31, 2015, all of Dominion Gas’ commodity derivatives were with affiliates. See Notes 7 and 9 for more information.

Dominion Gas participates in certain Dominion benefit plans as described in Note 18. In Dominion Gas’ Consolidated Balance Sheets at ~~June~~September 30, 2016 and December 31, 2015, amounts due from Dominion associated with these benefit plans included in noncurrent pension and other postretirement benefit assets were ~~$674~~$686 million and $652 million, respectively, and amounts due to Dominion at ~~June 30, 2016 and~~ December 31, 2015 included in other deferred credits and other liabilities were immaterial. There were no such amounts due to Dominion at September 30, 2016.

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 amounts recognized for these services were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015		2016		2015		2016		2015
(millions)
Purchases of natural gas and transportation and storage services from affiliates	$	2	$	2	$	5	$	4	$	2	$	3	$	7	$	7
Sales of natural gas and transportation and storage services to affiliates		18		17		35		35		16		17		51		52
Services provided by related parties⁽¹⁾		33		34		72		68		36		30		108		99
Services provided to related parties⁽²⁾		33		25		60		45		34		30		94		75

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


	June 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
(millions)
Other receivables⁽¹⁾	$	8	$	7	$	9	$	7
Customer receivables from related parties		10		4		1		4
Imbalances receivable from affiliates⁽²⁾		3		1		1		1
Affiliated notes receivable⁽³⁾		16		14		17		14

(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 intercompany revolving credit agreement with Dominion were immaterial and $95 million as of ~~June~~September 30, 2016 and December 31, 2015, respectively. Interest charges related to Dominion Gas’ total borrowings from Dominion were immaterial for the three and ~~six~~nine months ended ~~June~~September 30, 2016 and 2015.

In the first quarter of 2016, the Companies announced an organizational design initiative that will reduce their total workforces during 2016. The goal of the organizational design initiative was to streamline leadership structure and push decision making lower while also improving efficiency. During the ~~six~~nine months ended ~~June~~September 30, 2016, Dominion recorded a $65 million ($40 million after-tax) charge, including $33 million ($20 million after-tax) at Virginia Power and $8 million ($5 million after-tax) at Dominion Gas, primarily reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other costs related to the organizational design initiative. The terms of the severance under the organizational design initiative were consistent with the Companies’ existing severance plans.

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


	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	2016			2015			2016			2015			2016			2015			2016			2015
(millions)
Three Months Ended June 30,
Three Months Ended September 30,
Service cost													$	30		$	32		$	7		$	10
Interest cost														79			71			16			17
Expected return on plan assets														(141	)		(132	)		(28	)		(29	)
Amortization of prior service credit														—			—			(9	)		(7	)
Amortization of net actuarial loss														29			40			2			1

Net periodic benefit cost (credit)													$	(3	)	$	11		$	(12	)	$	(8	)

Nine Months Ended September 30,
Service cost	$	28		$	31		$	8		$	10		$	87		$	95		$	23		$	30
Interest cost		78			72			17			16			234			215			50			50
Expected return on plan assets		(139	)		(133	)		(30	)		(30	)		(419	)		(398	)		(87	)		(88	)
Amortization of prior service cost (credit)		1			1			(7	)		(6	)		1			1			(23	)		(20	)
Amortization of net actuarial loss		27			40			2			2			84			120			5			4

Net periodic benefit cost (credit)	$	(5	)	$	11		$	(10	)	$	(8	)	$	(13	)	$	33		$	(32	)	$	(24	)

Six Months Ended June 30,
Service cost	$	57		$	63		$	16		$	20
Interest cost		155			144			34			33
Expected return on plan assets		(278	)		(266	)		(59	)		(59	)
Amortization of prior service cost (credit)		1			1			(14	)		(13	)
Amortization of net actuarial loss		55			80			3			3

Net periodic benefit cost (credit)	$	(10	)	$	22		$	(20	)	$	(16	)

In the third quarter of 2016, Dominion remeasured an other postretirement benefit plan as a result of an amendment that changed post-65 retiree medical coverage for certain current and future Local 50 retirees effective April 1, 2017. The remeasurement resulted in a decrease in Dominion’s accumulated postretirement benefit obligation of $37 million. The impact of the remeasurement on net periodic benefit credit was recognized prospectively from the remeasurement date and is expected to increase the net periodic benefit credit for 2016 by $9 million. The discount rate used for the remeasurement was 3.71% and the demographic and mortality assumptions were updated using plan-specific studies and mortality improvement scales. The expected long-term rate of return used was consistent with the measurement as of December 31, 2015.

During the ~~six~~nine months ended ~~June~~September 30, 2016, 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 2016.

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, 2015. See Note 17 for more information.

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						Pension Benefits						Other Postretirement Benefits
	2016			2015			2016			2015			2016			2015			2016			2015 ��
(millions)
Three Months Ended June 30,
Three Months Ended September 30,
Service cost	$	4		$	4		$	2		$	1		$	3		$	4		$	1		$	2
Interest cost		7			7			4			4			7			7			3			3
Expected return on plan assets		(34	)		(32	)		(7	)		(6	)		(33	)		(31	)		(5	)		(6	)
Amortization of net actuarial loss		4			5			1			—			3			5			—			1

Net periodic benefit credit	$	(19	)	$	(16	)	$	—		$	(1	)	$	(20	)	$	(15	)	$	(1	)	$	—

Six Months Ended June 30,
Nine Months Ended September 30,
Service cost	$	7		$	7		$	3		$	3		$	10		$	11		$	4		$	5
Interest cost		15			14			7			7			22			21			10			10
Expected return on plan assets		(67	)		(63	)		(12	)		(12	)		(100	)		(94	)		(17	)		(18	)
Amortization of net actuarial loss		7			10			1			1			10			15			1			2

Net periodic benefit credit	$	(38	)	$	(32	)	$	(1	)	$	(1	)	$	(58	)	$	(47	)	$	(2	)	$	(1	)

During the ~~six~~nine months ended ~~June~~September 30, 2016, 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 2016.

The Companies are organized primarily on the basis of products and services sold in the United States. A description of the operations included in the Companies’ primary operating segments is as follows:

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

The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and 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 in allocating resources.

In the ~~six~~nine months ended ~~June~~September 30, 2016, Dominion reported an after-tax net expense of ~~$37~~$63 million for specific items in the Corporate and Other segment, with ~~$26~~$22 million of these net expenses attributable to its operating segments. In the ~~six~~nine months ended ~~June~~September 30, 2015, Dominion reported an after-tax net expense of ~~$64~~$82 million for specific items in the Corporate and Other segment, with ~~$62~~$80 million of these net expenses attributable to its operating segments.

The net expense for specific items attributable to Dominion’s operating segments in 2016 primarily related to the impact of the following ~~item:~~items:

The net expense for specific items in 2015 primarily related to the impact of the following items, all of which were attributable to Dominion Generation:

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


	DVP		Dominion Generation⁽¹⁾		Dominion Energy⁽¹⁾		Corporate and Other			Adjustments/ Eliminations⁽¹⁾			Consolidated Total		DVP		Dominion Generation⁽¹⁾		Dominion Energy⁽¹⁾		Corporate and Other			Adjustments/ Eliminations⁽¹⁾			Consolidated Total
(millions)
Three Months Ended June 30, 2016
Total revenue from external customers	$	512	$	1,564	$	391	$	3		$	128		$	2,598
Intersegment revenue		6		2		124		133			(265	)		—

Total operating revenue		518		1,566		515		136			(137	)		2,598
Net income attributable to Dominion		104		171		162		15			—			452

Three Months Ended June 30, 2015
Three Months Ended September 30, 2016
Total revenue from external customers	$	500	$	1,652	$	463	$	4		$	128		$	2,747	$	614	$	1,947	$	359	$	2		$	210		$	3,132
Intersegment revenue		5		6		115		144			(270	)		—		6		2		205		144			(357	)		—

Total operating revenue		505		1,658		578		148			(142	)		2,747		620		1,949		564		146			(147	)		3,132
Net income (loss) attributable to Dominion		117		250		129		(83	)		—			413		139		650		135		(234	)		—			690

Six Months Ended June 30, 2016
Three Months Ended September 30, 2015
Total revenue from external customers	$	1,068	$	3,257	$	876	$	6		$	312		$	5,519	$	539	$	1,892	$	377	$	—		$	163		$	2,971
Intersegment revenue		11		5		302		325			(643	)		—		4		2		159		128			(293	)		—

Total operating revenue		1,079		3,262		1,178		331			(331	)		5,519		543		1,894		536		128			(130	)		2,971
Net income (loss) attributable to Dominion		224		416		348		(12	)		—			976		125		390		153		(75	)		—			593

Six Months Ended June 30, 2015
Nine Months Ended September 30, 2016
Total revenue from external customers	$	1,064	$	3,641	$	999	$	(9	)	$	461		$	6,156	$	1,682	$	5,204	$	1,235	$	8		$	522		$	8,651
Intersegment revenue		10		9		425		286			(730	)		—		17		7		507		469			(1,000	)		—

Total operating revenue		1,074		3,650		1,424		277			(269	)		6,156		1,699		5,211		1,742		477			(478	)		8,651
Net income (loss) attributable to Dominion		257		512		356		(176	)		—			949		363		1,066		483		(246	)		—			1,666

Nine Months Ended September 30, 2015
Total revenue from external customers															$	1,603	$	5,533	$	1,376	$	(9	)	$	624		$	9,127
Intersegment revenue																14		11		584		414			(1,023	)		—

Total operating revenue																1,617		5,544		1,960		405			(399	)		9,127
Net income (loss) attributable to Dominion																382		902		509		(251	)		—			1,542

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

The 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 in allocating resources.

In the ~~six~~nine months ended ~~June~~September 30, 2016, Virginia Power reported an after-tax net expense of ~~$19~~$18 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segments. In the ~~six~~nine months ended ~~June~~September 30, 2015, Virginia Power reported an after-tax net expense of ~~$87~~$101 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segments.

The net expense for specific items attributable to Virginia Power’s operating segments in 2016 primarily related to the impact of the following item:

The net expense for specific items in 2015 primarily related to the impact of the following items, all of which were attributable to Dominion Generation:

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


	DVP		Dominion Generation		Corporate and Other			Consolidated Total		DVP		Dominion Generation		Corporate and Other			Consolidated Total
(millions)
Three Months Ended June 30, 2016
Three Months Ended September 30, 2016
Operating revenue	$	512	$	1,264	$	—		$	1,776	$	617	$	1,594	$	—		$	2,211
Net income		104		174		2			280		140		359		4			503

Three Months Ended June 30, 2015
Three Months Ended September 30, 2015
Operating revenue	$	502	$	1,311	$	—		$	1,813	$	541	$	1,523	$	(6	)	$	2,058
Net income (loss)		117		155		(26	)		246		125		273		(13	)		385

Six Months Ended June 30, 2016
Nine Months Ended September 30, 2016
Operating revenue	$	1,069	$	2,597	$	—		$	3,666	$	1,686	$	4,191	$	—		$	5,877
Net income (loss)		222		340		(19	)		543		362		699		(15	)		1,046

Six Months Ended June 30, 2015
Nine Months Ended September 30, 2015
Operating revenue	$	1,069	$	2,896	$	(15	)	$	3,950	$	1,610	$	4,419	$	(21	)	$	6,008
Net income (loss)		257		345		(87	)		515		382		618		(100	)		900

The Corporate and Other Segment of Dominion Gasprimarily includes specific items attributable to Dominion Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources 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~~nine months ended ~~June~~September 30, 2016, Dominion Gas reported an after-tax net ~~expense~~benefit of $2$5 million for specific items in the Corporate and Other segment, ~~all~~with after-tax net expense of ~~which was~~$7 million attributable to its operating segment. In the ~~six~~nine months ended ~~June~~September 30, 2015, Dominion Gas reported no amounts for specific items in the Corporate and Other segment.

The net expense for specific items in 2016 primarily related to an $8 million ($5 million after-tax) charge related to an organizational design initiative.

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


	Dominion Energy		Corporate and Other			Consolidated Total		Dominion Energy		Corporate and Other			Consolidated Total
(millions)
Three Months Ended June 30, 2016
Three Months Ended September 30, 2016
Operating revenue								$	382	$	—		$	382
Net income									77		6			83

Three Months Ended September 30, 2015
Operating revenue	$	368	$	—		$	368	$	365	$	—		$	365
Net income (loss)		108		(3	)		105		113		(2	)		111

Three Months Ended June 30, 2015
Nine Months Ended September 30, 2016
Operating revenue	$	395	$	—		$	395	$	1,181	$	—		$	1,181
Net income (loss)		87		(2	)		85		288		(2	)		286

Six Months Ended June 30, 2016
Nine Months Ended September 30, 2015
Operating revenue	$	799	$	—		$	799	$	1,291	$	—		$	1,291
Net income (loss)		211		(8	)		203		364		(7	)		357

Six Months Ended June 30, 2015
Operating revenue	$	926	$	—		$	926
Net income (loss)		251		(5	)		246

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.

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:

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, 2015.

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.

As of ~~June~~September 30, 2016, 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, 2015. 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.


	2016		2015		$ Change		2016		2015		$ Change
(millions, except EPS)
Second Quarter
Third Quarter
Net income attributable to Dominion	$	452	$	413	$	39	$	690	$	593	$	97
Diluted EPS		0.73		0.70		0.03		1.10		1.00		0.10

Year-To-Date
Net income attributable to Dominion	$	976	$	949	$	27	$	1,666	$	1,542	$	124
Diluted EPS		1.61		1.60		0.01		2.71		2.60		0.11

Net income attributable to Dominion increased 9%16%, primarily due to ~~the absence of charges related to ash pond and landfill closure costs at certain utility generation facilities, a decrease~~higher renewable energy investment tax credits, an increase in electric utility ~~capacity related expenses and~~sales to retail customers from an increase in cooling degree days and the new PJM capacity performance market effective June 2016. These increases were partially offset by transaction and transition costs due to the Dominion Questar Combination.

Net income attributable to Dominion increased 8%, primarily due to higher renewable energy investment tax credits and the new PJM capacity performance market effective June 2016. These increases were partially offset by a decrease in gains from agreements to convey shale development rights underneath several natural gas storage ~~fields. These increases were partially offset by a decrease in electric utility sales to retail customers from a reduction in cooling degree days.~~

~~Net income attributable to Dominion increased 3%, primarily~~fields and transaction and transition costs due to the absence of the write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015 and higher anticipated renewable energy investment tax credits. These increases were partially offset by a decrease in electric utility sales to retail customers from reductions in cooling and heating degree days and organizational design initiative costs.Dominion Questar Combination.

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


	Second Quarter							Year-To-Date							Third Quarter								Year-To-Date
	2016		2015		$ Change			2016		2015		$ Change			2016			2015		$ Change			2016		2015		$ Change
(millions)
Operating revenue	$	2,598	$	2,747	$	(149	)	$	5,519	$	6,156	$	(637	)	$	3,132		$	2,971	$	161		$	8,651	$	9,127	$	(476	)
Electric fuel and other energy-related purchases		551		591		(40	)		1,185		1,544		(359	)		606			636		(30	)		1,791		2,180		(389	)
Purchased electric capacity		45		90		(45	)		113		184		(71	)
Purchased (excess) electric capacity																(6	)		75		(81	)		107		259		(152	)
Purchased gas		56		111		(55	)		175		361		(186	)		77			85		(8	)		252		446		(194	)

Net revenue		1,946		1,955		(9	)		4,046		4,067		(21	)		2,455			2,175		280			6,501		6,242		259

Other operations and maintenance		665		709		(44	)		1,368		1,311		57			765			564		201			2,133		1,875		258
Depreciation, depletion and amortization		361		339		22			712		682		30			400			355		45			1,112		1,037		75
Other taxes		139		134		5			303		299		4			145			133		12			448		432		16
Other income		72		56		16			126		116		10			63			11		52			189		127		62
Interest and related charges		239		221		18			465		444		21			250			230		20			715		674		41
Income tax expense		152		190		(38	)		331		489		(158	)		230			305		(75	)		561		794		(233	)

Depreciation, depletion and amortizationincreased ~~planned~~13%, primarily due to various expansion projects being placed into service ($32 million) and ~~unplanned outage days~~the Dominion Questar Combination ($9 million).

Other income increased $52 million, primarily due to higher realized gains (including investment income) on nuclear decommissioning trust funds ($25 million) and an increase in ~~the second quarter of 2016~~earnings from equity method investments ($5915 million).

Income tax expense decreased 25%, primarily due to higher renewable energy investment tax credits ($63 million) and a settlement with a tax authority ($12 million), partially offset by higher ~~realized prices~~pre-tax income ($1421 million) ~~and an increase due to additional solar generating facilities ($9 million); and~~.

~~These decreases were partially offset by a $30~~A $355 million increase from electric utility operations, primarily reflecting:

~~Other operations and maintenance~~ ~~decreased 6%, primarily reflecting:~~

~~Income tax expense~~ ~~decreased 20%, primarily due to higher anticipated renewable energy investment tax credits ($21 million) and the impact of a state legislative change ($17 million).~~

~~These decreases were partially offset by an $83 million increase from electric utility operations, primarily reflecting:~~

Other incomeincreased 49%, primarily due to an increase in earnings from equity method investments ($43 million) and an increase in AFUDC costs associated with rate-regulated projects ($9 million).

Income tax expensedecreased ~~32%~~29%, primarily due to higher ~~anticipated~~ renewable energy investment tax credits ($90153 million), lower ~~pretax~~pre-tax income ($4827 million) ~~and~~, the impact of a state legislative change ($17 million) and a settlement with a tax authority ($12 million).

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									Net Income attributable to Dominion									Diluted EPS
	2016			2015			$ Change			2016			2015			$ Change			2016			2015			$ Change			2016			2015			$ Change
(millions, except EPS)
Second Quarter
Third Quarter
DVP	$	104		$	117		$	(13	)	$	0.17		$	0.20		$	(0.03	)	$	139		$	125		$	14		$	0.22		$	0.21		$	0.01
Dominion Generation⁽¹⁾		171			250			(79	)		0.28			0.42			(0.14	)		650			390			260			1.04			0.66			0.38
Dominion Energy⁽¹⁾		162			129			33			0.26			0.22			0.04			135			153			(18	)		0.21			0.26			(0.05	)

Primary operating segments		437			496			(59	)		0.71			0.84			(0.13	)		924			668			256			1.47			1.13			0.34
Corporate and Other		15			(83	)		98			0.02			(0.14	)		0.16			(234	)		(75	)		(159	)		(0.37	)		(0.13	)		(0.24	)

Consolidated	$	452		$	413		$	39		$	0.73		$	0.70		$	0.03		$	690		$	593		$	97		$	1.10		$	1.00		$	0.10

Year-To-Date
DVP	$	224		$	257		$	(33	)	$	0.37		$	0.43		$	(0.06	)	$	363		$	382		$	(19	)	$	0.59		$	0.64		$	(0.05	)
Dominion Generation⁽¹⁾		416			512			(96	)		0.69			0.87			(0.18	)		1,066			902			164			1.74			1.52			0.22
Dominion Energy⁽¹⁾		348			356			(8	)		0.57			0.60			(0.03	)		483			509			(26	)		0.78			0.86			(0.08	)

Primary operating segments		988			1,125			(137	)		1.63			1.90			(0.27	)		1,912			1,793			119			3.11			3.02			0.09
Corporate and Other		(12	)		(176	)		164			(0.02	)		(0.30	)		0.28			(246	)		(251	)		5			(0.40	)		(0.42	)		0.02

Consolidated	$	976		$	949		$	27		$	1.61		$	1.60		$	0.01		$	1,666		$	1,542		$	124		$	2.71		$	2.60		$	0.11

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


	Second Quarter							Year-To-Date							Third Quarter							Year-To-Date
	2016		2015		% Change			2016		2015		% Change			2016		2015		% Change			2016		2015		% Change
Electricity delivered (million MWh)		18.9		20.1		(6	)%		40.1		43.0		(7	)%		24.1		22.6		7	%		64.2		65.6		(2	)%
Degree days (electric distribution service area):
Cooling		425		645		(34	)		429		645		(33	)		1,326		1,174		13			1,755		1,819		(4	)
Heating		367		214		71			2,247		2,578		(13	)		—		—		—			2,247		2,578		(13	)
Average electric distribution customer accounts (thousands)⁽¹⁾		2,545		2,521		1			2,543		2,519		1			2,552		2,526		1			2,546		2,522		1

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


	Second Quarter 2016 vs. 2015 Increase (Decrease)						Year-To-Date 2016 vs. 2015 Increase (Decrease)						Third Quarter 2016 vs. 2015 Increase (Decrease)						Year-To-Date 2016 vs. 2015 Increase (Decrease)
	Amount			EPS			Amount			EPS			Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(11	)	$	(0.02	)	$	(26	)	$	(0.04	)	$	12		$	0.02		$	(14	)	$	(0.02	)
Other		—			—			(5	)		(0.01	)		5			0.01			—			—
FERC transmission equity return		10			0.02			21			0.04			9			0.01			30			0.05
Storm damage and service restoration		(10	)		(0.02	)		(12	)		(0.02	)		(5	)		(0.01	)		(17	)		(0.03	)
Depreciation and amortization														(2	)		—			(7	)		(0.01	)
Other		(2	)		—			(11	)		(0.02	)		(5	)		(0.01	)		(11	)		(0.02	)
Share dilution		—			(0.01	)		—			(0.01	)		—			(0.01	)		—			(0.02	)

Change in net income contribution	$	(13	)	$	(0.03	)	$	(33	)	$	(0.06	)	$	14		$	0.01		$	(19	)	$	(0.05	)

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


	Second Quarter							Year-To-Date							Third Quarter							Year-To-Date
	2016		2015		% Change			2016		2015		% Change			2016		2015		% Change			2016		2015		% Change
Electricity supplied (million MWh):
Utility		20.1		20.4		(1	)%		42.3		43.3		(2	)%		24.8		22.9		8	%		67.1		66.2		1	%
Merchant		6.2		6.6		(6	)		13.3		13.0		2			7.9		7.6		4			21.2		20.6		3
Degree days (electric utility service area):
Cooling		425		645		(34	)		429		645		(33	)		1,326		1,174		13			1,755		1,819		(4	)
Heating		367		214		71			2,247		2,578		(13	)		—		—		—			2,247		2,578		(13	)

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


	Second Quarter 2016 vs. 2015 Increase (Decrease)						Year-To-Date 2016 vs. 2015 Increase (Decrease)						Third Quarter 2016 vs. 2015 Increase (Decrease)						Year-To-Date 2016 vs. 2015 Increase (Decrease)
	Amount			EPS			Amount			EPS			Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(23	)	$	(0.04	)	$	(54	)	$	(0.09	)	$	32		$	0.05		$	(22	)	$	(0.04	)
Other		5			0.01			2			—			10			0.02			12			0.02
Renewable energy investment tax credits⁽¹⁾		(30	)		(0.05	)		(31	)		(0.05	)		212			0.35			182			0.31
Capacity related expenses		26			0.04			40			0.07
Electric capacity														49			0.08			89			0.16
Outage costs		(24	)		(0.04	)		(23	)		(0.04	)		1			—			(22	)		(0.04	)
Merchant generation margin		(20	)		(0.03	)		(28	)		(0.05	)		(14	)		(0.02	)		(42	)		(0.07	)
Rate adjustment clause equity return		10			0.02			16			0.03			2			—			18			0.03
Depreciation and amortization														(5	)		(0.01	)		(15	)		(0.03	)
Other		(23	)		(0.04	)		(18	)		(0.03	)		(27	)		(0.04	)		(36	)		(0.06	)
Share dilution		—			(0.01	)		—			(0.02	)		—			(0.05	)		—			(0.06	)

Change in net income contribution	$	(79	)	$	(0.14	)	$	(96	)	$	(0.18	)	$	260		$	0.38		$	164		$	0.22

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


	Second Quarter							Year-To-Date							Third Quarter							Year-To-Date
	2016		2015		% Change			2016		2015		% Change			2016		2015		% Change			2016		2015			% Change
Gas distribution throughput (bcf):
Gas distribution throughput (bcf)⁽¹⁾:
Sales		3		3		—	%		16		19		(16	)%		2		2		—	%		18		21			(14	)%
Transportation		99		90		10			258		252		2			106		89		19			364		341			7
Heating degree days (gas distribution service area)		729		568		28			3,413		4,143		(18	)
Average gas distribution customer accounts (thousands)⁽¹⁾:
Heating degree days (gas distribution service area):
Eastern region																22		48		(54	)		3,435		4,191			(18	)
Western region⁽¹⁾																39		—		100			39		—			100
Average gas distribution customer accounts (thousands)⁽¹⁾⁽²⁾:
Sales		224		231		(3	)		233		239		(3	)		472		234		102			329		237			39
Transportation		1,079		1,069		1			1,073		1,065		1			1,069		1,050		2			1,072		1,060	��		1
Average retail energy marketing customer accounts (thousands)⁽¹⁾		1,376		1,288		7			1,364		1,269		7
Average retail energy marketing customer accounts (thousands)⁽²⁾																1,377		1,319		4			1,368		1,285			6

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


	Second Quarter 2016 vs. 2015 Increase (Decrease)					Year-To-Date 2016 vs. 2015 Increase (Decrease)						Third Quarter 2016 vs. 2015 Increase (Decrease)						Year-To-Date 2016 vs. 2015 Increase (Decrease)
	Amount		EPS			Amount			EPS			Amount			EPS			Amount			EPS
(millions, except EPS)
Gas distribution margin:
Weather	$	1	$	—		$	(7	)	$	(0.01	)	$	—		$	—		$	(7	)	$	(0.01	)
Other		1		—			6			0.01			5			0.01			11			0.02
Assignment of shale development rights		21		0.04			(20	)		(0.03	)		(27	)		(0.06	)		(47	)		(0.09	)
Retail energy marketing operations		6		0.01			9			0.01
Dominion Questar Combination													5			0.01			5			0.01
Other		4		—			4			—			(1	)		—			12			0.02
Share dilution		—		(0.01	)		—			(0.01	)		—			(0.01	)		—			(0.03	)

Change in net income contribution	$	33	$	0.04		$	(8	)	$	(0.03	)	$	(18	)	$	(0.05	)	$	(26	)	$	(0.08	)


	Second Quarter									Year-To-Date									Third Quarter									Year-To-Date
	2016			2015			$ Change			2016			2015			$ Change			2016			2015			$ Change			2016			2015			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	12		$	(17	)	$	29		$	(26	)	$	(62	)	$	36		$	4		$	(18	)	$	22		$	(22	)	$	(80	)	$	58
Specific items attributable to corporate operations		(1	)		1			(2	)		(11	)		(2	)		(9	)		(30	)		—			(30	)		(41	)		(2	)		(39	)

Total specific items		11			(16	)		27			(37	)		(64	)		27			(26	)		(18	)		(8	)		(63	)		(82	)		19
Other corporate operations:
Renewable energy investment tax credits		51			4			47			132			10			122			(143	)		5			(148	)		(11	)		15			(26	)
Other		(47	)		(71	)		24			(107	)		(122	)		15			(65	)		(62	)		(3	)		(172	)		(184	)		12

Total other corporate operations		4			(67	)		71			25			(112	)		137			(208	)		(57	)		(151	)		(183	)		(169	)		(14	)

Total net income (expense)	$	15		$	(83	)	$	98		$	(12	)	$	(176	)	$	164
Total net expense																			$	(234	)	$	(75	)	$	(159	)	$	(246	)	$	(251	)	$	5
EPS impact	$	0.02		$	(0.14	)	$	0.16		$	(0.02	)	$	(0.30	)	$	0.28		$	(0.37	)	$	(0.13	)	$	(0.24	)	$	(0.40	)	$	(0.42	)	$	0.02

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. See Note 19 to the Consolidated Financial Statements in this report for discussion of these items in more detail. Corporate and Other also includes specific items attributable to the Corporate and Other segment. For the three and nine months ended September 30, 2016, this primarily included $46 million and $50 million, respectively, of after-tax transaction and transition costs associated with the Dominion Questar Combination.


	Second Quarter						Year-To-Date						Third Quarter						Year-To-Date
	2016		2015		$ Change		2016		2015		$ Change		2016		2015		$ Change		2016		2015		$ Change
(millions)
Net income	$	280	$	246	$	34	$	543	$	515	$	28	$	503	$	385	$	118	$	1,046	$	900	$	146

Net income increased ~~14%~~31%, primarily due to ~~the absence of charges related to ash pond and landfill closure costs at certain utility generation facilities, a decrease in capacity related expenses and~~ an increase ~~in rate adjustment clause revenue. These increases were partially offset by a decrease~~ in sales to retail customers from ~~a reduction~~an increase in cooling degree ~~days.~~days and the new PJM capacity performance market effective June 2016.

Net income increased 5%16%, primarily due to an increase in rate adjustment clause revenue, the new PJM capacity performance market effective June 2016 and the absence of ~~the~~a write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015, a decrease in capacity related expenses and a decrease in charges related to ash pond and landfill closure costs at certain utility generation facilities. These increases were partially offset by a decrease in sales to retail customers from reductions in cooling and heating degree days.2015.

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


	Second Quarter							Year-To-Date							Third Quarter								Year-To-Date
	2016		2015		$ Change			2016		2015		$ Change			2016			2015		$ Change			2016		2015		$ Change
(millions)
Operating revenue	$	1,776	$	1,813	$	(37	)	$	3,666	$	3,950	$	(284	)	$	2,211		$	2,058	$	153		$	5,877	$	6,008	$	(131	)
Electric fuel and other energy-related purchases		475		497		(22	)		1,011		1,307		(296	)		516			554		(38	)		1,527		1,861		(334	)
Purchased electric capacity		45		90		(45	)		113		184		(71	)
Purchased (excess) electric capacity																(6	)		75		(81	)		107		259		(152	)

Net revenue		1,256		1,226		30			2,542		2,459		83			1,701			1,429		272			4,243		3,888		355

Other operations and maintenance		386		445		(59	)		836		841		(5	)		443			375		68			1,279		1,216		63
Depreciation and amortization		247		231		16			495		469		26			270			244		26			765		713		52
Other taxes		70		69		1			144		143		1			74			69		5			218		212		6
Other income		18		21		(3	)		34		36		(2	)		13			13		—			47		49		(2	)
Interest and related charges		113		108		5			227		216		11			118			116		2			345		332		13
Income tax expense		178		148		30			331		311		20			306			253		53			637		564		73

Other operations and maintenance ~~decreased 13%~~increased 18%, primarily reflecting:

Depreciation and amortization increased 11%, primarily due to various expansion projects being placed into service.

Income tax expense increased ~~20%~~21%, primarily due to higher pre-tax income.

Other operations and maintenance ~~decreased 1%~~increased 5%, primarily reflecting:


	Second Quarter						Year-To-Date							Third Quarter							Year-To-Date
	2016		2015		$ Change		2016		2015		$ Change			2016		2015		$ Change			2016		2015		$ Change
(millions)
Net income	$	105	$	85	$	20	$	203	$	246	$	(43	)	$	83	$	111	$	(28	)	$	286	$	357	$	(71	)

Net income ~~increased 24%~~decreased 25%, primarily due to ~~an increase~~a decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields.

Net income decreased ~~17%~~20%, primarily due to ~~a decrease in gas transportation and storage activities and~~ a decrease in gains from agreements to convey shale development rights underneath several natural gas storage ~~fields.~~fields and a decrease in gas transportation and storage activities.

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


	Second Quarter							Year-To-Date							Third Quarter							Year-To-Date
	2016		2015		$ Change			2016		2015		$ Change			2016		2015		$ Change			2016		2015		$ Change
(millions)
Operating revenue	$	368	$	395	$	(27	)	$	799	$	926	$	(127	)	$	382	$	365	$	17		$	1,181	$	1,291	$	(110	)
Purchased gas		16		21		(5	)		50		95		(45	)		21		8		13			71		103		(32	)
Other energy-related purchases		1		7		(6	)		4		13		(9	)		4		4		—			8		17		(9	)

Net revenue		351		367		(16	)		745		818		(73	)		357		353		4			1,102		1,171		(69	)

Other operations and maintenance		74		124		(50	)		198		198		—			133		63		70			331		261		70
Depreciation and amortization		52		53		(1	)		95		104		(9	)		55		53		2			150		157		(7	)
Other taxes		39		37		2			91		92		(1	)		36		35		1			127		127		—
Other income		9		4		5			15		13		2			7		4		3			22		17		5
Interest and related charges		23		18		5			45		35		10			23		18		5			68		53		15
Income tax expense		67		54		13			128		156		(28	)		34		77		(43	)		162		233		(71	)

Other operations and maintenance ~~decreased 40%,~~increased $70 million, primarily reflecting:

~~Other income~~~~increased $5 million, primarily due to a gain on the sale of 0.65% of the non-controlling partnership interest in Iroquois.~~

Interest and related chargesincreased 28%, primarily due to higher interest expense ~~on long-term debt~~ resulting from ~~a debt issuance~~the issuances of senior notes in November ~~2015.~~2015 and the second quarter of 2016.

Income tax expense~~increased 24%~~decreased 56%, primarily reflecting ~~higher~~lower pre-tax ~~income.~~income ($29 million) and a settlement with a tax authority ($12 million).

Other operations and maintenance expense ~~was $198 million for both the six months ended June 30, 2016 and 2015. These amounts reflect the impact of the following items:~~increased 27%, primarily reflecting:

Other incomeincreased 29%, primarily due to a gain on the sale of 0.65% of the non-controlling partnership interest in Iroquois.

Interest and related chargesincreased ~~29%~~28%, primarily due to higher interest expense ~~on long-term debt~~ resulting from ~~a debt issuance~~the issuances of senior notes in November ~~2015.~~2015 and the second quarter of 2016.

Income tax expensedecreased ~~18%~~30%, primarily reflecting lower pre-tax ~~income.~~income ($56 million) and a settlement with a tax authority ($12 million).

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.

In September 2015, Dominion initiated a program to purchase from the market up to $50 million of common units representing limited partner interests in Dominion ~~Midstream. The common units may be acquired by Dominion over the 12 month period following commencement of the program at the discretion of management.~~Midstream, which expired in September 2016. During the ~~six~~nine months ended ~~June~~September 30, 2016, Dominion purchased approximately ~~489,000~~658,000 common units for ~~$13~~$17 million. ~~Dominion still has the ability to purchase $12 million of common units under the program.~~

Given the sufficiency of operating and other cash flows at the Dominion level, no dividends were declared or paid to Dominion by either Virginia Power or Dominion Gas during the first quarter of 2016. During the second quarter of 2016, no dividends were declared or paid to Dominion by Virginia Power. During the third quarter of 2016, no dividends were declared or paid to Dominion by either Virginia Power or Dominion Gas.

At ~~June~~September 30, 2016, Dominion had ~~$2.0~~$3.1 billion of unused capacity under its credit facilities. See Note 14 to the Consolidated Financial Statements for more information.


	2016			2015			2016			2015
(millions)
Cash and cash equivalents at January 1	$	607		$	318		$	607		$	318
Cash flows provided by (used in):
Operating activities		2,018			2,160			3,386			3,453
Investing activities		(3,725	)		(3,084	)		(9,029	)		(4,350	)
Financing activities		1,477			877			5,287			817

Net decrease in cash and cash equivalents		(230	)		(47	)		(356	)		(80	)

Cash and cash equivalents at June 30	$	377		$	271
Cash and cash equivalents at September 30							$	251		$	238

Net cash provided by Dominion’s operating activities decreased ~~$142~~$67 million, primarily due to ~~higher~~changes in net margin collateral requirements and ~~the impact from unfavorable weather in 2016,~~higher operations and maintenance expenses, partially offset by the benefit from the new PJM capacity performance market, higher deferred fuel cost recoveries in its Virginia ~~jurisdiction.~~jurisdiction, and net changes in other working capital items.

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

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, 2015.

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~~September 30, 2016 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		Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade⁽¹⁾	$	87	$	31	$	56	$	55	$	15	$	40
Non-investment grade⁽²⁾		2		—		2		4		—		4
No external ratings:
Internally rated - investment grade⁽³⁾		11		—		11		7		—		7
Internally rated - non-investment grade⁽⁴⁾		11		1		10		30		—		30

Total	$	111	$	32	$	79	$	96	$	15	$	81

Net cash used in Dominion’s investing activities increased ~~$641 million,~~$4.7 billion, primarily due to the Dominion Questar Combination and higher capital expenditures, ~~and the restricted cash for the Questar Combinations,~~ partially offset by the ~~absences~~absence of Dominion’s acquisition of DCG in 2015 and the acquisition of fewer solar development projects in ~~2015.~~2016.

Dominion relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed further inCredit Ratingsand Debt Covenants in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015, 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.

Net cash provided by Dominion’s financing activities increased ~~$600 million,~~$4.5 billion, primarily reflecting ~~an increase in~~higher net debt issuances and higher common stock ~~issuances.~~issuances in connection with the Dominion Questar Combination.

See ~~Note~~Notes 3 and 14 to the Consolidated Financial Statements in this report for further information regarding Dominion’s credit facilities, liquidity and significant financing transactions.

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In theCredit Ratings section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015, 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.

In March 2016, Fitch Ratings Ltd. and Standard & Poor’s changed the rating for Dominion’s junior subordinated debt securities to account for its inability to defer interest payments on the remarketed 2013 Series A RSNs. Junior subordinated debt securities with an interest deferral feature are rated one notch lower by Fitch Ratings Ltd. and Standard & Poor’s (BBB-) than

junior subordinated debt securities without an interest deferral feature (BBB). See Note 14 to the Consolidated Financial Statements for a description of the remarketed notes. As of ~~June~~September 30, 2016, there have been no additional changes in Dominion’s credit ratings.

In theDebt Covenants section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015, there is a discussion on the various covenants present in the enabling agreements underlying Dominion’s debt. As of ~~June~~September 30, 2016, there have been no material changes to debt covenants, nor any events of default under Dominion’s debt covenants. Pursuant to a waiver received in April 2016 and in connection with the closing of the Dominion Questar Combination, the 65% maximum debt to total capital ratio in Dominion’s credit agreements ~~will,~~has, with respect to Dominion only, ~~and upon closing of the Questar Combination, be~~been temporarily increased to 70% until the end of the ~~fourth~~ fiscal quarter ~~following closing (including the fiscal quarter in which the closing occurs).~~ending June 30, 2017.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

AsOther than debt and financing obligations associated with the Dominion Questar Combination discussed in Note 3 to the Consolidated Financial Statements, as of ~~June~~September 30, 2016, 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, 2015.

As of ~~June~~September 30, 2016, with the exception of the leasing arrangement described herein, 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, 2015.

In July 2016, Dominion signed an agreement with a lessor to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors to fund the project costs, totaling $365 million. The project is expected to be completed by mid-2019. Dominion has been appointed to act as the

construction agent for the lessor, during which time Dominion will request cash draws from ~~the~~ the lessor and debt investors to fund all project costs. If the project is terminated under certain events of default, Dominion could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion could be required to pay up to 100% of the then funded amount.

The five-year lease term will commence once construction is substantially complete and the facility is able to be occupied. At the end of the initial lease term, Dominion can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion may be required to make a payment to the lessor, up to 87% of project costs, for the difference between the project costs and sale proceeds.

The respective transactions have been structured so that Dominion is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. The financial accounting treatment of the lease agreement will be impacted by the new accounting standard issued in February 2016. Dominion will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.

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 withItem 1. Business andFuture Issues and Other Matters in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015 andFuture Issues and Other Matters in MD&A in the Companies’ Quarterly ~~Report~~Reports on Form 10-Q for the ~~quarter~~quarters ended March 31, 2016 and June 30, 2016.

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, 2015, and Note 15 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016, June 30, 2016 and in this report for additional information on various environmental matters.

In August 2015, the EPA issued final carbon standards for existing fossil fuel power plants. Known as the Clean Power Plan, the rule 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 impose standards of performance limits for existing fossil fuel-fired electric generating units or equivalent statewide intensity-based or mass-based CO₂ binding goals or limits. States are required to submit interim plans to the EPA by September 2016 identifying how they will comply with the rule, with final plans due by September 2018. The EPA also proposed a federal plan and model trading rules that, when finalized, states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. Virginia Power’s most recent integrated resources plan filed in May 2016 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. The final rule has been challenged in the United States Court of Appeals for the District of Columbia Circuit. In February 2016, the United States Supreme Court issued a stay of the Clean Power Plan until the disposition of the petitions challenging the rule now before the Court of Appeals, and, if such petitions are filed in the future, before the United States Supreme Court. Dominion does not know whether these legal challenges will impact the submittal deadlines for the state implementation plans. Also in February 2016, the Governor of Virginia announced that it will continue development of a state plan. Until all court challenges have been resolved, the state plans are developed and the EPA approves the plans, Dominion cannot predict the potential financial statement impacts. However, Dominion believes the potential expenditures to comply based on the four alternative plans discussed in the most recent integrated resources plan will be material.

See Item 3. Legal Proceedings in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015, Notes 12 and 15 to the Consolidated Financial Statements andItem 1. Legal Proceedingsin the Companies’ Quarterly ~~Report~~Reports on Form 10-Q for the ~~quarter~~quarters ended March 31, 2016, June 30, 2016 and ~~Notes 12 and 15 to the Consolidated Financial Statements and~~~~Item 1. Legal Proceedings~~ in this report for additional information on various legal matters.

In April 2016, the labor contract between Dominion and Local 69 expired. In August 2016, the parties reached a tentative agreement for a new labor contract, however, the agreement was not submitted to members of Local 69 for approval. In September 2016, following a temporary lock out of union members, Local 69 agreed to not strike at DTI and Hope at least through April 1, 2017. In exchange, DTI and Hope agreed to recall the union members to work and not lock them out during that period. Contract negotiations resumed in October 2016 and are continuing. Local 69 represents about 759 DTI employees in West Virginia, New York, Pennsylvania, Ohio and Virginia and about 151 Hope employees in West Virginia.

See Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015, and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly ~~Report~~Reports on Form 10-Q for the ~~quarter~~quarters ended March 31, 2016, June 30, 2016 and in this report for additional information on various regulatory matters.

In August 2016, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in multiple Virginia counties approximately 28 miles of the existing 500 kV transmission line between the Carson switching station and a terminus located near the Rogers Road switching station under construction in Greensville County, Virginia, along with associated work at the Carson switching station. The total estimated cost of the project is approximately $53 million. This case is pending.

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.

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% change in commodity prices or interest rates.

To manage price risk, Dominion and Virginia Power hold commodity-based derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products and Dominion Gas 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 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~~decrease in commodity prices would have resulted in a decrease in fair value of ~~$20~~$34 million and $24 million of Dominion’s commodity-based derivative instruments as of ~~June~~September 30, 2016 and December 31, 2015, respectively.

A hypothetical 10% decrease in commodity prices would have resulted in a decrease in the fair value of ~~$54~~$51 million and $42 million of Virginia Power’s commodity-based derivative instruments as of ~~June~~September 30, 2016 and December 31, 2015, respectively.

A hypothetical 10% increase in commodity prices would have resulted in a decrease in fair value of $6$4 million and $5 million of Dominion Gas’ commodity-based derivative instruments as of ~~June~~September 30, 2016 and December 31, 2015, respectively.

The impact of a change in energy commodity prices on the Companies’ commodity-based 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-based financial 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. Physical commodity-based derivative instruments will be recognized as a gross revenue or expense based upon the transaction price and volume.

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~~September 30, 2016 or December 31, 2015.

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

As of ~~June~~September 30, 2016, Dominion and Virginia Power had ~~$3.1~~$2.8 billion and $1.8 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted

in a decrease of ~~$52~~$2 million and ~~$42~~$46 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at ~~June~~September 30, 2016. As of December 31, 2015, Dominion, Virginia Power and Dominion Gas had $4.6 billion, $2.0 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 $71 million, $52 million and $2 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2015.

In June 2016, Dominion Gas entered into foreign currency swaps with the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of ~~June~~September 30, 2016, Dominion Gas had $280 million (€250 million) in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% increase in market interest rates would ~~not~~ have resulted in a ~~material change~~$4 million decrease in ~~earnings~~the fair value of Dominion Gas’ foreign currency swaps at ~~June~~September 30, 2016.

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.

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 ~~$67~~$113 million and ~~$102~~$134 million for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, respectively, and $184 million for the year ended December 31, 2015. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion recorded in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of ~~$98~~$146 million for the ~~six~~nine months ended ~~June~~September 30, ~~2016. Dominion recorded in AOCI~~2016, and ~~regulatory liabilities,~~ a net decrease in unrealized gains on these investments of ~~$62~~$260 million and $157 million for the ~~six~~nine months ended ~~June~~September 30, 2015 and ~~$157 million~~ for the year ended December 31, ~~2015.~~2015, respectively.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of ~~$32~~$51 million and ~~$38~~$67 million for the ~~six~~nine months ended ~~June~~September 30, 2016 and 2015, respectively, and $88 million for the year ended December 31, 2015. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of ~~$53~~$77 million for the ~~six~~nine months ended ~~June~~September 30, ~~2016. Virginia Power recorded in AOCI~~2016, and ~~regulatory liabilities,~~ a net decrease in unrealized gains on these investments of ~~$21~~$123 million and $76 million for the ~~six~~nine months ended ~~June~~September 30, 2015 and ~~$76 million~~ for the year ended December 31, ~~2015.~~2015, 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.

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.

Dominion is currently in the process of integrating Dominion Questar’s operations, processes and internal controls. See Note 3 for more information relating to the Dominion Questar Combination.

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 January 2015, DTI received a draft consent agreement from the EPA in connection with alleged violations of certain CAA monitoring and permitting requirements at the Hastings facility. The draft consent agreement included a proposed penalty of approximately $160,000. In September 2016, DTI and the EPA finalized a consent agreement and final order resolving this matter, which included a final penalty of $98,000.

In January 2016, Virginia Power self-reported a release of mineral oil from the Crystal City substation and began extensive cleanup. In February 2016, Virginia Power received a notice of violation from the VDEQ relating to this matter. Virginia Power has assumed the role of responsible party and is continuing to cooperate with ongoing requirements for investigative and corrective action. In September 2016, Virginia Power received a proposed consent order from the VDEQ related to this matter. The proposed consent order includes a penalty of approximately $260,000, which is inclusive of both the Crystal City substation oil release and an oil release from another Virginia Power facility in 2016. The portion of the penalty attributable to the other facility represents less than $100,000 of the total proposed penalty. Virginia Power has agreed to the terms of the proposed consent order, which is subject to final approval by the Virginia State Water Control Board.

See the following for discussions on various environmental and other regulatory proceedings to which the Companies are a party, which information is incorporated herein by reference:

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, 2015, 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, 2015. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, seeForward-Looking Statements in MD&A in this report.


Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas

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 Quarterly Report on Form 10-Q for the quarter ended ~~June~~September 30, 2016, filed on ~~August 3,~~November 9, 2016, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statement of Equity, (iv) Consolidated Statements of Comprehensive Income, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Virginia Electric and Power Company’s and Dominion Gas Holdings, LLC’s Quarterly Report on Form 10-Q for the quarter ended ~~June~~September 30, 2016, filed on ~~August 3,~~November 9, 2016, 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

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.


Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas

4.3	2016 Series A Purchase Contract and Pledge Agreement, dated August 15, 2016, between the Company and Deutsche Bank Trust Company Americas, as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary (Exhibit 4.7, Form 8-K filed August 15, 2016, File No. 1-8489).	X

12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X


~~Exhibit~~ ~~Number~~	~~Description~~	~~Dominion~~	~~Virginia~~ ~~Power~~	~~Dominion~~ ~~Gas~~

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 Quarterly Report on Form 10-Q for the quarter ended ~~June~~September 30, 2016, filed on ~~August 3,~~November 9, 2016, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statement of Equity, (iv) Consolidated Statements of Comprehensive Income, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Virginia Electric and Power Company’s and Dominion Gas Holdings, LLC’s Quarterly Report on Form 10-Q for the quarter ended ~~June~~September 30, 2016, filed on ~~August 3,~~November 9, 2016, 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


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
001-37591	DOMINION GAS HOLDINGS, LLC	46-3639580


		Page Number

	Glossary of Terms		3

	PART I. Financial Information

~~Item��~~Item 1.	Financial Statements		6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		7984
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		9398
Item 4.	Controls and Procedures		95100

	PART II. Other Information
Item 1.	Legal Proceedings		96101
Item 1A.	Risk Factors		96101
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		96102
Item 6.	Exhibits		97103


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

2016 Equity Units		Dominion’s 2016 Series A Equity Units issued in August 2016

AFUDC		Allowance for funds used during construction

AMR		Automated meter reading program deployed by East Ohio

AOCI		Accumulated other comprehensive income (loss)

~~APCo~~		~~Appalachian Power Company~~

AROs		Asset retirement obligations

ARP		Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the CAA

Atlantic Coast Pipeline		Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion, Duke ~~Energy Corporation, Piedmont Natural~~and Southern Company Gas ~~Company, Inc. and AGL Resources Inc.~~

BACT		Best available control technology

bcf		Billion cubic feet

~~Bear Garden~~bcfe		~~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 Energy II, LLC~~Billion cubic feet equivalent

BREDL		Blue Ridge Environmental Defense League

Brunswick County		A 1,358 MW combined cycle, natural gas-fired power station in Brunswick County, Virginia

CAA		Clean Air Act

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

CO₂		Carbon dioxide

COL		Combined Construction Permit and Operating License

~~Columbia to Eastover Project~~		Project to provide 15,800 Dths/day of firm transportation service from an existing interconnect with Southern Natural Gas Company, LLC in Aiken County, South Carolina and provide for a receipt point change of 2,200 Dths/day under an existing contract from an existing interconnect with Transco in Cherokee County, South Carolina for a total 18,000 Dths/day, to a new delivery point for the International Paper Company at its pulp and paper mill known as the Eastover Plant in Richland County, South Carolina

Companies		Dominion, Virginia Power and Dominion Gas, collectively

Contribution Agreement		Contribution, Conveyance and Assumption Agreement between Dominion and Dominion Midstream dated October 28, 2016

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

DCG		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, as of May 2016, holds a 24.07% noncontrolling partnership interest in Iroquois

Dominion Midstream		The legal entity, Dominion Midstream Partners, LP, one or more of its consolidated subsidiaries, Cove Point Holdings, Iroquois GP Holding Company, LLC and DCG (beginning April 1, 2015), or the entirety of Dominion Midstream Partners, LP, and its consolidated subsidiaries

~~DRS~~Dominion Questar		The legal entity, Dominion ~~Resources Services, Inc.~~Questar Corporation (formerly known as Questar Corporation), one or more of its consolidated subsidiaries, or operating segments, or the entirety of Dominion Questar Corporation and its consolidated subsidiaries


	Three Months Ended September 30,				Nine Months Ended September 30,
	2016⁽¹⁾		2015		2016⁽¹⁾		2015
(millions, except EPS)
Operating Revenue	$	3,261	$	3,113	$	9,410	$	9,897
Net income attributable to Dominion		732		626		1,835		1,700
Earnings Per Common Share – Basic	$	1.17	$	1.05	$	2.99	$	2.88
Earnings Per Common Share – Diluted	$	1.17	$	1.05	$	2.99	$	2.87


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)~~


Issuance Date	Units Issued		Total Net Proceeds		Total Long- term Debt		RSN Annual Interest Rate⁽¹⁾			Stock Purchase Contract Annual Rate			Stock Purchase Contract Liability		Stock Purchase Contract Settlement Date		RSN Maturity Date⁽²⁾
(millions, except interest rates)
8/15/2016		28	$	1,374.8	$	1,400.0		2.000	%		4.750	%	$	190.6		8/15/2019


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
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
	Nonregulated retail energy marketing⁽²⁾	X


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⁾
4/1/16-4/30/16		1,639	$	75.39		—	19,629,059 shares/ $1.18 billion
5/1/16-5/31/16		6,739		71.47		—	19,629,059 shares/ $1.18 billion
6/1/16-6/30/16		1,527		71.68		—	19,629,059 shares/ $1.18 billion

Total		9,905	$	72.15		—	19,629,059 shares/ $1.18 billion


						DOMINION RESOURCES, INC. Registrant

~~August 3,~~November 9, 2016						/s/ Michele L. Cardiff
						Michele L. Cardiff Vice President, Controller and Chief Accounting Officer

						VIRGINIA ELECTRIC AND POWER COMPANY Registrant

~~August 3,~~November 9, 2016						/s/ Michele L. Cardiff
						Michele L. Cardiff Vice President, Controller and Chief Accounting Officer

						DOMINION GAS HOLDINGS, LLC Registrant

~~August 3,~~November 9, 2016						/s/ Michele L. Cardiff
						Michele L. Cardiff Vice President, Controller and Chief Accounting Officer

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