10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended September 30, 2016

or

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

For the transition period from                      to                     

Commission File Number	Exact name of registrants as specified in their charters, address of principal executive offices and registrants’ telephone number	I.R.S. Employer Identification Number
001-08489	DOMINION RESOURCES, INC.	54-1229715
000-55337	VIRGINIA ELECTRIC AND POWER COMPANY	54-0418825
001-37591	DOMINION GAS HOLDINGS, LLC	46-3639580

120 Tredegar Street

Richmond, Virginia 23219

(804) 819-2000

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

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

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

Dominion Gas Holdings, LLC    Yes  x    No  ¨

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

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

Dominion Gas Holdings, LLC    Yes  x    No  ¨

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

Dominion Resources, Inc.

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

Virginia Electric and Power Company

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

Dominion Gas Holdings, LLC

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

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

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

Dominion Gas Holdings, LLC    Yes  ¨    No  x

At October 15, 2016, the latest practicable date for determination, Dominion Resources, Inc. had 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.

COMBINED INDEX

		Page Number
	Glossary of Terms		3
	PART I. Financial Information
Item 1.	Financial Statements		6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		84
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		98
Item 4.	Controls and Procedures		100
	PART II. Other Information
Item 1.	Legal Proceedings		101
Item 1A.	Risk Factors		101
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		102
Item 6.	Exhibits		103

2

GLOSSARY OF TERMS

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

Abbreviation or Acronym	Definition
2013 Equity Units	Dominion’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013
2014 Equity Units	Dominion’s 2014 Series A Equity Units issued in July 2014
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)
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 and Southern Company Gas
BACT	Best available control technology
bcf	Billion cubic feet
bcfe	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
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
Dominion Questar	The legal entity, Dominion 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

3

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 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 NRG effective November 2016
Greensville County	An approximately 1,588 MW proposed natural gas-fired combined-cycle power station in Greensville County, Virginia
Heating degree days	Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
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 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
NOx	Nitrogen oxide
North Carolina Commission	North Carolina Utilities Commission
NRC	Nuclear Regulatory Commission

4

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 deployed by Hope
PSD	Prevention of Significant Deterioration
PSMP	Pipeline Safety Management Program deployed by East Ohio
Questar Gas	Questar 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 the entirety of Questar Pipeline, LLC and its consolidated subsidiaries
REIT	Real estate investment trust
Rider BW	A rate adjustment clause associated with the recovery of costs related to Brunswick County
Rider U	A rate adjustment clause associated with the recovery of new underground distribution facilities
Rider US-2	A rate adjustment clause associated with the recovery of costs related to Woodland, Scott Solar and Whitehouse
Riders C1A and C2A	Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in DSM cases
ROE	Return on equity
RSN	Remarketable subordinated note
Scott Solar	An approximately 17 MW 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
Utah Commission	Public Service Commission of Utah
VDEQ	Virginia Department of Environmental Quality
VEBA	Voluntary Employees’ Beneficiary Association
VIE	Variable interest entity
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
West Virginia Commission	Public Service Commission of West Virginia
White River Hub	White River Hub, LLC, a FERC-regulated transporter of natural gas in western Colorado
Whitehouse	An approximately 20 MW utility-scale solar power station under construction in Louisa County, Virginia
Woodland	An approximately 19 MW utility-scale solar power station under construction in Isle of Wight County, Virginia
Wyoming Commission	Wyoming Public Service Commission

5

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016			2015		2016		2015
(millions, except per share amounts)
Operating Revenue	$	3,132		$	2,971	$	8,651	$	9,127
Operating Expenses
Electric fuel and other energy-related purchases		606			636		1,791		2,180
Purchased (excess) electric capacity		(6	)		75		107		259
Purchased gas		77			85		252		446
Other operations and maintenance		765			564		2,133		1,875
Depreciation, depletion and amortization		400			355		1,112		1,037
Other taxes		145			133		448		432
Total operating expenses		1,987			1,848		5,843		6,229
Income from operations		1,145			1,123		2,808		2,898
Other income		63			11		189		127
Interest and related charges		250			230		715		674
Income from operations including noncontrolling interests before income tax expense		958			904		2,282		2,351
Income tax expense		230			305		561		794
Net Income Including Noncontrolling Interests		728			599		1,721		1,557
Noncontrolling Interests		38			6		55		15
Net Income Attributable to Dominion	$	690		$	593	$	1,666	$	1,542
Earnings Per Common Share
Net income attributable to Dominion - Basic	$	1.10		$	1.00	$	2.72	$	2.61
Net income attributable to Dominion - Diluted		1.10			1.00		2.71		2.60
Dividends Declared Per Common Share	$	0.7000		$	0.6475	$	2.1000	$	1.9425

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

6

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
(millions)
Net income including noncontrolling interests	$	728		$	599		$	1,721		$	1,557
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		14			(7	)		56			25
Changes in unrealized net gains (losses) on investment securities(2)		31			(59	)		72			(55	)
Changes in unrecognized pension and other postretirement benefit costs(3)		15			(9	)		15			(6	)
Amounts reclassified to net income:
Net derivative gains-hedging activities(4)		(34	)		(53	)		(141	)		(53	)
Net realized gains on investment securities(5)		(13	)		(2	)		(23	)		(35	)
Net pension and other postretirement benefit costs(6)		9			14			25			39
Changes in other comprehensive income (loss) from equity method investees(7)		—			1			(1	)		—
Total other comprehensive income (loss)		22			(115	)		3			(85	)
Comprehensive income including noncontrolling interests		750			484			1,724			1,472
Comprehensive income attributable to noncontrolling interests		38			6			55			15
Comprehensive income attributable to Dominion	$	712		$	478		$	1,669		$	1,457

(1) Net of $(8) million and $— million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $(34) million and $(20) million tax for the nine months ended September 30, 2016 and 2015, respectively.

(2) Net of $(18) million and $55 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $(43) million and $50 million tax for the nine months ended September 30, 2016 and 2015, respectively.

(3) Net of $(10) million and $(9) million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $(10) million and $(6) million tax for the nine months ended September 30, 2016 and 2015, respectively.

(4) Net of $21 million and $30 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $88 million and $34 million tax for the nine months ended September 30, 2016 and 2015, respectively.

(5) Net of $7 million and $— million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $13 million and $20 million tax for the nine months ended September 30, 2016 and 2015, respectively.

(6) Net of $(4) million and $(7) million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $(16) million and $(25) million tax for the nine months ended September 30, 2016 and 2015, respectively.

(7) Net of $— million and $(1) million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $— million tax for both the nine months ended September 30, 2016 and 2015.

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

7

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,      2016			December 31,      2015(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	251		$	607
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)		133			169
Inventories		1,516			1,348
Prepayments		147			198
Other		493			667
Total current assets		3,799			4,189
Investments
Nuclear decommissioning trust funds		4,427			4,183
Investment in equity method affiliates		1,498			1,320
Other		299			271
Total investments		6,224			5,774
Property, Plant and Equipment
Property, plant and equipment		68,282			57,776
Accumulated depreciation, depletion and amortization		(19,394	)		(16,222	)
Total property, plant and equipment, net		48,888			41,554
Deferred Charges and Other Assets
Goodwill		6,405			3,294
Pension and other postretirement benefit assets		1,095			943
Regulatory assets		2,143			1,865
Other		1,045			1,029
Total deferred charges and other assets		10,688			7,131
Total assets	$	69,599		$	58,648

(1) Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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

8

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	September 30,      2016			December 31,      2015(1)
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	2,931		$	1,825
Short-term debt		3,097			3,509
Accounts payable		685			726
Accrued interest, payroll and taxes		800			515
Other(2)		1,514			1,544
Total current liabilities		9,027			8,119
Long-Term Debt
Long-term debt		23,356			20,048
Junior subordinated notes		2,980			1,340
Remarketable subordinated notes		2,371			2,080
Total long-term debt		28,707			23,468
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		8,675			7,414
Asset retirement obligations		2,153			1,887
Regulatory liabilities		2,597			2,285
Other		2,248			1,873
Total deferred credits and other liabilities		15,673			13,459
Total liabilities		53,407			45,046
Commitments and Contingencies (see Note 15)
Equity
Common stock – no par(3)		8,592			6,680
Retained earnings		6,837			6,458
Accumulated other comprehensive loss		(471	)		(474	)
Total common shareholders’ equity		14,958			12,664
Noncontrolling interests		1,234			938
Total equity		16,192			13,602
Total liabilities and equity	$	69,599		$	58,648

(1) Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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

(3) 1 billion shares authorized; 627 million shares and 596 million shares outstanding at September 30, 2016 and December 31, 2015, respectively.

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

9

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

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

10

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended September 30,	2016			2015
(millions)
Operating Activities
Net income including noncontrolling interests	$	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)		1,325			1,250
Deferred income taxes and investment tax credits		481			703
Gains on the sales of assets and equity method investment in Iroquois		(50	)		(123	)
Other adjustments		(78	)		(1	)
Changes in:
Accounts receivable		19			229
Inventories		(10	)		(3	)
Deferred fuel and purchased gas costs, net		84			70
Prepayments		71			45
Accounts payable		(89	)		(222	)
Accrued interest, payroll and taxes		205			(13	)
Margin deposit assets and liabilities		1			205
Other operating assets and liabilities		(294	)		(244	)
Net cash provided by operating activities		3,386			3,453
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(4,536	)		(3,632	)
Acquisition of Dominion Questar, net of cash acquired		(4,372	)		—
Acquisition of solar development projects		(21	)		(278	)
Acquisition of DCG		—			(497	)
Proceeds from sales of securities		1,009			937
Purchases of securities		(1,065	)		(921	)
Proceeds from assignments of shale development rights		10			80
Other		(54	)		(39	)
Net cash used in investing activities		(9,029	)		(4,350	)
Financing Activities
Repayment of short-term debt, net		(713	)		(220	)
Issuance of short-term notes		1,200			—
Repayment and repurchase of short-term notes		(600	)		—
Issuance and remarketing of long-term debt		5,730			2,262
Repayment and repurchase of long-term debt		(1,169	)		(675	)
Proceeds from sale of interest in merchant solar projects		117			—
Contributions from SunEdison to Four Brothers and Three Cedars		178			—
Issuance of common stock		2,079			717
Common dividend payments		(1,287	)		(1,150	)
Other		(248	)		(117	)
Net cash provided by financing activities		5,287			817
Decrease in cash and cash equivalents		(356	)		(80	)
Cash and cash equivalents at beginning of period		607			318
Cash and cash equivalents at end of period	$	251		$	238
Supplemental Cash Flow Information
Significant noncash investing and financing activities(1)(2):
Accrued capital expenditures	$	341		$	389
Dominion Midstream’s acquisition of a noncontrolling partnership interest in Iroquois in exchange for issuance of Dominion Midstream common units		—			216

(1) See Note 3 for noncash activities related to the acquisitions of Four Brothers and Three Cedars in 2015.

(2) See Note 14 for noncash activities related to the remarketing of RSNs in 2016.

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

11

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016			2015		2016		2015
(millions)
Operating Revenue(1)	$	2,211		$	2,058	$	5,877	$	6,008
Operating Expenses
Electric fuel and other energy-related purchases(1)		516			554		1,527		1,861
Purchased (excess) electric capacity		(6	)		75		107		259
Other operations and maintenance:
Affiliated suppliers		73			64		238		208
Other		370			311		1,041		1,008
Depreciation and amortization		270			244		765		713
Other taxes		74			69		218		212
Total operating expenses		1,297			1,317		3,896		4,261
Income from operations		914			741		1,981		1,747
Other income		13			13		47		49
Interest and related charges		118			116		345		332
Income before income tax expense		809			638		1,683		1,464
Income tax expense		306			253		637		564
Net Income	$	503		$	385	$	1,046	$	900

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

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

12

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
(millions)
Net income	$	503		$	385		$	1,046		$	900
Other comprehensive income (loss), net of taxes:
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
Net realized gains on nuclear decommissioning trust funds(4)		(1	)		(1	)		(2	)		(4	)
Total other comprehensive income (loss)		2			(18	)		(8	)		(16	)
Comprehensive income	$	505		$	367		$	1,038		$	884

(1) Net of $1 million and $3 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $10 million and $1 million tax for the nine months ended September 30, 2016 and 2015, respectively.

(2) Net of $(2) million and $5 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $(6) million and$5 million tax for the nine months ended September 30, 2016 and 2015, respectively.

(3) Net of $— million tax for both the three months ended September 30, 2016 and 2015, and net of $(1) million and $— million tax for the nine months ended September 30, 2016 and 2015, respectively.

(4) Net of $1 million and $2 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $2 million and $3 million tax for the nine months ended September 30, 2016 and 2015, respectively.

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

13

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,      2016			December 31, 2015(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	18		$	18
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)		87			109
Affiliated receivables		1			296
Inventories (average cost method)		836			873
Prepayments		23			38
Regulatory assets		197			326
Other(2)		33			22
Total current assets		2,132			2,504
Investments
Nuclear decommissioning trust funds		2,074			1,945
Other		3			3
Total investments		2,077			1,948
Property, Plant and Equipment
Property, plant and equipment		39,428			37,639
Accumulated depreciation and amortization		(12,314	)		(11,708	)
Total property, plant and equipment, net		27,114			25,931
Deferred Charges and Other Assets
Regulatory assets		897			667
Other(2)		527			515
Total deferred charges and other assets		1,424			1,182
Total assets	$	32,747		$	31,565

(1) Virginia Power’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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

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

14

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	September 30,      2016		December 31, 2015(1)
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	679	$	476
Short-term debt		965		1,656
Accounts payable		330		366
Payables to affiliates		84		73
Affiliated current borrowings		—		376
Accrued interest, payroll and taxes		321		190
Regulatory liabilities		75		35
Other(2)		690		558
Total current liabilities		3,144		3,730
Long-Term Debt		8,963		8,892
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		5,017		4,654
Asset retirement obligations		1,194		1,104
Regulatory liabilities		1,967		1,929
Other(2)		784		615
Total deferred credits and other liabilities		8,962		8,302
Total liabilities		21,069		20,924
Commitments and Contingencies (see Note 15)
Common Shareholder’s Equity
Common stock – no par(3)		5,738		5,738
Other paid-in capital		1,113		1,113
Retained earnings		4,795		3,750
Accumulated other comprehensive income		32		40
Total common shareholder’s equity		11,678		10,641
Total liabilities and shareholder’s equity	$	32,747	$	31,565

(1) Virginia Power’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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

(3) 500,000 shares authorized; 274,723 shares outstanding at September 30, 2016 and December 31, 2015.

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

15

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended September 30,	2016			2015
(millions)
Operating Activities
Net income	$	1,046		$	900
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		903			844
Deferred income taxes and investment tax credits		369			9
Other adjustments		(15	)		20
Changes in:
Accounts receivable		(99	)		10
Affiliated receivables and payables		306			(33	)
Inventories		37			11
Prepayments		15			228
Deferred fuel expenses, net		79			40
Accounts payable		4			(62	)
Accrued interest, payroll and taxes		131			137
Other operating assets and liabilities		8			70
Net cash provided by operating activities		2,784			2,174
Investing Activities
Plant construction and other property additions		(1,835	)		(1,840	)
Purchases of nuclear fuel		(106	)		(100	)
Proceeds from sales of securities		478			407
Purchases of securities		(513	)		(423	)
Other		(11	)		(38	)
Net cash used in investing activities		(1,987	)		(1,994	)
Financing Activities
Issuance (repayment) of short-term debt, net		(691	)		1
Repayment of affiliated current borrowings, net		(376	)		(427	)
Issuance and remarketing of long-term debt		750			1,112
Repayment of long-term debt		(476	)		(421	)
Common dividend payments to parent		—			(416	)
Other		(4	)		(5	)
Net cash used in financing activities		(797	)		(156	)
Increase in cash and cash equivalents		—			24
Cash and cash equivalents at beginning of period		18			15
Cash and cash equivalents at end of period	$	18		$	39
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	209		$	139

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

16

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Operating Revenue(1)	$	382	$	365	$	1,181	$	1,291
Operating Expenses
Purchased gas(1)		21		8		71		103
Other energy-related purchases		4		4		8		17
Other operations and maintenance:
Affiliated suppliers		20		12		63		50
Other		113		51		268		211
Depreciation and amortization		55		53		150		157
Other taxes		36		35		127		127
Total operating expenses		249		163		687		665
Income from operations		133		202		494		626
Other income		7		4		22		17
Interest and related charges		23		18		68		53
Income from operations before income taxes		117		188		448		590
Income tax expense		34		77		162		233
Net Income	$	83	$	111	$	286	$	357

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

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

17

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
(millions)
Net income	$	83		$	111		$	286		$	357
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		9			3			(6	)		2
Amounts reclassified to net income:
Net derivative gains-hedging activities(2)		(1	)		(2	)		(3	)		(3	)
Net pension and other postretirement benefit costs(3)		1			1			2			3
Total other comprehensive income (loss)		9			2			(7	)		2
Comprehensive income	$	92		$	113		$	279		$	359

(1) Net of $(3) million and $(1) million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $5 million and $— million tax for the nine months ended September 30, 2016 and 2015, respectively.

(2) Net of $2 million and $1 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $2 million and $1 million tax for the nine months ended September 30, 2016 and 2015, respectively.

(3) Net of $(1) million tax for both the three months ended September 30, 2016 and 2015, and net of $(2) million and $(3) million tax for the nine months ended September 30, 2016 and 2015, respectively.

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

18

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2016			December 31, 2015(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	8		$	13
Customer receivables (less allowance for doubtful accounts of $1 at both dates)(2)		158			219
Other receivables (less allowance for doubtful accounts of $1 and $2)(2)		12			7
Affiliated receivables		5			98
Inventories		94			78
Prepayments		73			88
Other(2)		55			63
Total current assets		405			566
Investments		98			104
Property, Plant and Equipment
Property, plant and equipment		10,259			9,693
Accumulated depreciation and amortization		(2,808	)		(2,690	)
Total property, plant and equipment, net		7,451			7,003
Deferred Charges and Other Assets
Goodwill		542			542
Pension and other postretirement benefit assets(2)		1,613			1,510
Other(2)		634			583
Total deferred charges and other assets		2,789			2,635
Total assets	$	10,743		$	10,308

(1) Dominion Gas’ Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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

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

19

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	September 30, 2016			December 31, 2015(1)
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	400		$	400
Short-term debt		60			391
Accounts payable		124			201
Payables to affiliates		20			22
Affiliated current borrowings		—			95
Accrued interest, payroll and taxes		176			183
Other(2)		162			183
Total current liabilities		942			1,475
Long-Term Debt		3,545			2,869
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,414			2,214
Other(2)		395			432
Total deferred credits and other liabilities		2,809			2,646
Total liabilities		7,296			6,990
Commitments and Contingencies (see Note 15)
Equity
Membership interests		3,553			3,417
Accumulated other comprehensive loss(2)		(106	)		(99	)
Total equity		3,447			3,318
Total liabilities and equity	$	10,743		$	10,308

(1) Dominion Gas’ Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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

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

20

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended September 30,	2016			2015
(millions)
Operating Activities
Net income	$	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		(50	)		(123	)
Depreciation and amortization		150			157
Deferred income taxes and investment tax credits		204			75
Other adjustments		3			4
Changes in:
Accounts receivable		56			150
Affiliated receivables and payables		91			(22	)
Deferred purchased gas costs, net		7			19
Prepayments		15			145
Accounts payable		(76	)		(112	)
Accrued interest, payroll and taxes		(7	)		(45	)
Other operating assets and liabilities		(176	)		(109	)
Net cash provided by operating activities		503			496
Investing Activities
Plant construction and other property additions		(610	)		(514	)
Proceeds from sale of equity method investment in Iroquois		7			—
Proceeds from assignments of shale development rights		10			80
Other		(10	)		(5	)
Net cash used in investing activities		(603	)		(439	)
Financing Activities
Issuance (repayment) of short-term debt, net		(331	)		382
Issuance of long-term debt		680			—
Repayment of affiliated current borrowings, net		(95	)		(186	)
Distribution payments to parent		(150	)		(244	)
Other		(9	)		—
Net cash provided by (used in) financing activities		95			(48	)
Increase (decrease) in cash and cash equivalents		(5	)		9
Cash and cash equivalents at beginning of period		13			9
Cash and cash equivalents at end of period	$	8		$	18
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	42		$	46

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

21

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

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

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the SEC, the Companies’ accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with GAAP. These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015.

In the Companies’ opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position as of September 30, 2016, their results of operations for the three and nine months ended September 30, 2016 and 2015, their cash flows for the nine months ended September 30, 2016 and 2015 and Dominion’s changes in equity for the nine months ended 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 September 30, 2016, Dominion owns the general partner and 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 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.

Note 3. Acquisitions and Dispositions

Dominion

Acquisition of Dominion Questar

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

22

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, at closing, each share of issued and outstanding Dominion Questar common stock was converted into the right to receive $25.00 per share in cash. The total consideration was $4.4 billion 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 of 2016 Equity Units, (2) August 2016 issuance of $1.3 billion of senior notes, (3) September 2016 borrowing of $1.2 billion under a private placement term loan agreement and (4) $500 million of the proceeds from the April 2016 issuance of common stock. See Note 14 for more information.

Purchase Price Allocation

Dominion Questar’s assets acquired and liabilities assumed were measured at estimated fair value at the closing date and are included in the Dominion Energy operating segment. The majority of Dominion Questar’s operations are subject to 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 recognized and disclosed in the reporting period in which the adjustment amounts are determined.

23

	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

(1) Includes $40 million for an equity method investment in White River Hub. The fair value adjustment on the equity method investment in White River Hub is considered to be equity method goodwill and is not amortized.

(2) Nonregulated property, plant and equipment, excluding land, will be depreciated over remaining useful lives primarily ranging from 9 to 18 years.

(3) Includes $301 million of short-term debt, of which $24 million is outstanding at September 30, 2016, as well as a $250 million short-term note which matures in February 2017 and bears interest at a variable rate.

(4) Unsecured senior notes have maturities which range from 2017 to 2048 and bear interest at rates from 2.98% to 7.20%.

(5) Includes a $35 million capital lease obligation with undiscounted future minimum lease payments of $1 million remaining in 2016, $4 million per year for 2017 through 2020, and $37 million in total thereafter.

Regulatory Matters

The transaction required approval of Dominion Questar’s shareholders, clearance from the Federal Trade Commission under the Hart-Scott-Rodino 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 May 2016, Dominion Questar’s shareholders voted to approve the Dominion Questar Combination. 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 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:

• Dominion will contribute $75 million toward the funding of Dominion Questar’s qualified and non-qualified defined-benefit pension plans and its other post-employment benefit plans within six months of the closing date. This contribution is expected to be made during the fourth quarter of 2016.

• Dominion committed to increasing Dominion Questar’s historical level of corporate contributions to charities by $1 million per year for at least five years.

• Questar Gas withdrew its general rate case filed in July 2016 with the Utah Commission and agreed to not file a general rate case with the Utah Commission to adjust its base distribution non-gas rates prior to July 2019, unless otherwise ordered by the Utah Commission. In addition, Questar Gas agreed not to file a general rate case with the Wyoming Commission with a requested rate effective date earlier than January 2020. This does not impact Questar Gas’s ability to adjust rates through various riders.

Results of Operations and Pro Forma Information

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 transition costs, of which $40 million and $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.

24

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.

	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

(1) Amounts include adjustments for non-recurring costs directly related to the Dominion Questar Combination.

Anticipated Contribution of Questar Pipeline to Dominion Midstream

In October 2016, Dominion entered into the Contribution Agreement under which Dominion will contribute Questar Pipeline to Dominion Midstream. Upon closing of the 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.

Non-Wholly-Owned Merchant Solar Projects

Acquisitions of Four Brothers and Three Cedars

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 September 30, 2016, a $7 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Four Brothers’ purpose is to operate four solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, with generating capacity of approximately 320 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 September 30, 2016, a $4 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Three Cedars’ purpose is to operate three solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, with generating capacity of approximately 210 MW, at a cost of approximately $450 million.

The Four Brothers and Three Cedars facilities operate under long-term power purchase, interconnection and operation and maintenance agreements. Dominion 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.

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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 nine months ended September 30, 2016. Subsequent to Dominion’s acquisition of Four Brothers and Three Cedars, SunEdison made contributions to Four Brothers and Three Cedars of $281 million in aggregate through September 30, 2016, which are reflected as noncontrolling interests in Dominion’s Consolidated Balance Sheets.

In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison.

Wholly-Owned Merchant Solar Projects

The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion in the 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	Initial Acquisition Cost (millions)(1)		Project Cost (millions)(2)		Date of Commercial Operations	MW Capacity
April 2015	EC&R NA Solar PV, LLC	1	California	Alamo	$	66	$	66	May 2015		20
April 2015	EDF Renewable Development, Inc.	3	California	Cottonwood(3)		106		106	May 2015		24
June 2015	EDF Renewable Development, Inc.	1	California	Catalina 2		68		68	July 2015		18
July 2015	SunPeak Solar, LLC	1	California	Imperial Valley 2		42		71	August 2015		20

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

(2) Includes acquisition cost.

(3) One of the projects, Marin Carport, began commercial operations in 2016.

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.

Sale of Interest in Merchant Solar Projects

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 September 30, 2016 nor are expected to occur in the remainder of 2016.

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Acquisition of DCG

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.

Dominion Gas

Assignments of Shale Development Rights

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. Also in connection with that agreement, in July 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. These gains are included in other operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.

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Note 4. Operating Revenue

The Companies’ operating revenue consists of the following:

	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

Note 5. Income Taxes

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
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	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		3.7			4.0			3.9			4.2			0.8			4.1
Investment tax credits		(10.4	)		(3.5	)		—			—			—			—
Production tax credits		(0.8	)		(0.8	)		(0.5	)		(0.5	)		—			—
State legislative change		(0.8	)		(0.2	)		—			—			—			—
Other, net		(2.1	)		(0.7	)		(0.5	)		(0.2	)		0.4			0.4
Effective tax rate		24.6	%		33.8	%		37.9	%		38.5	%		36.2	%		39.5	%

In 2016, Dominion’s effective tax rate reflects $23 million of 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.

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Note 6. Earnings Per Share

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions, except EPS)
Net income attributable to Dominion	$	690	$	593	$	1,666	$	1,542
Average shares of common stock outstanding – Basic		625.9		594.6		612.8		591.3
Net effect of dilutive securities(1)		0.1		0.9		1.0		1.4
Average shares of common stock outstanding – Diluted		626.0		595.5		613.8		592.7
Earnings Per Common Share – Basic	$	1.10	$	1.00	$	2.72	$	2.61
Earnings Per Common Share – Diluted	$	1.10	$	1.00	$	2.71	$	2.60

(1) Dilutive securities consist primarily of the 2013 Equity Units for the nine months ended September 30, 2016 and the three and nine months ended September 30, 2015. See Note 14 in this report and Note 17 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015 for more information.

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 nine months ended September 30, 2016 and 2015, as the dilutive stock price threshold was not met.

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Note 7. Accumulated Other Comprehensive Income

Dominion

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

	Deferred Gains and Losses on Derivatives- Hedging Activities			Unrealized Gains and Losses on Investment Securities			Unrecognized Pension and Other Postretirement Benefit Costs			Other Comprehensive Income (Loss) From Equity Method Investee			Total
(millions)
Three Months Ended 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	$	(146	)	$	519		$	(754	)	$	(5	)	$	(386	)
Other comprehensive income before reclassifications: gains (losses)		(7	)		(59	)		(9	)		1			(74	)
Amounts reclassified from AOCI(1): (gains) losses		(53	)		(2	)		14			—			(41	)
Net current-period other comprehensive income (loss)		(60	)		(61	)		5			1			(115	)
Ending balance	$	(206	)	$	458		$	(749	)	$	(4	)	$	(501	)
Nine Months Ended September 30, 2016
Beginning balance	$	(176	)	$	504		$	(797	)	$	(5	)	$	(474	)
Other comprehensive income before reclassifications: gains (losses)		56			72			15			(1	)		142
Amounts reclassified from AOCI(1): (gains) losses		(141	)		(23	)		25			—			(139	)
Net current-period other comprehensive income (loss)		(85	)		49			40			(1	)		3
Ending balance	$	(261	)	$	553		$	(757	)	$	(6	)	$	(471	)
Nine Months Ended September 30, 2015
Beginning balance	$	(178	)	$	548		$	(782	)	$	(4	)	$	(416	)
Other comprehensive income before reclassifications: gains (losses)		25			(55	)		(6	)		—			(36	)
Amounts reclassified from AOCI(1): (gains) losses		(53	)		(35	)		39			—			(49	)
Net current-period other comprehensive income (loss)		(28	)		(90	)		33			—			(85	)
Ending balance	$	(206	)	$	458		$	(749	)	$	(4	)	$	(501	)

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

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

Details About AOCI Components	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Three Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(64	)	Operating revenue
		1		Purchased gas
		1		Electric fuel and other energy-related purchases
Interest rate contracts		10		Interest and related charges
Foreign currency contracts		(3	)	Other income
		(55	)
Tax		21		Income tax expense
	$	(34	)

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Details About AOCI Components	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	$	(25	)	Other income
Impairment		5		Other income
		(20	)
Tax		7		Income tax expense
	$	(13	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(4	)	Other operations and maintenance
Actuarial (gains) losses		17		Other operations and maintenance
		13
Tax		(4	)	Income tax expense
	$	9
Three Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(87	)	Operating revenue
		2		Purchased gas
Interest rate contracts		2		Interest and related charges
		(83	)
Tax		30		Income tax expense
	$	(53	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(18	)	Other income
Impairment		16		Other income
		(2	)
Tax		—		Income tax expense
	$	(2	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(3	)	Other operations and maintenance
Actuarial (gains) losses		24		Other operations and maintenance
		21
Tax		(7	)	Income tax expense
	$	14
Nine Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(266	)	Operating revenue
		9		Purchased gas
		8		Electric fuel and other energy-related purchases
Interest rate contracts		21		Interest and related charges
Foreign currency contracts		(1	)	Other income
		(229	)
Tax		88		Income tax expense
	$	(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	)

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Details About AOCI Components	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(11	)	Other operations and maintenance
Actuarial (gains) losses		52		Other operations and maintenance
		41
Tax		(16	)	Income tax expense
	$	25
Nine Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(103	)	Operating revenue
		9		Purchased gas
Interest rate contracts		7		Interest and related charges
		(87	)
Tax		34		Income tax expense
	$	(53	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(82	)	Other income
Impairment		27		Other income
		(55	)
Tax		20		Income tax expense
	$	(35	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(9	)	Other operations and maintenance
Actuarial (gains) losses		73		Other operations and maintenance
		64
Tax		(25	)	Income tax expense
	$	39

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Dominion Gas

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

	Deferred Gains and Losses on Derivatives- Hedging Activities			Unrecognized Pension and Other Postretirement Benefit Costs			Total
(millions)
Three Months Ended September 30, 2016
Beginning balance	$	(34	)	$	(81	)	$	(115	)
Other comprehensive income before reclassifications: gains		9			—			9
Amounts reclassified from AOCI(1): (gains) losses		(1	)		1			—
Net current-period other comprehensive income		8			1			9
Ending balance	$	(26	)	$	(80	)	$	(106	)
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	)
Other comprehensive income before reclassifications: losses		(6	)		—			(6	)
Amounts reclassified from AOCI(1): (gains) losses		(3	)		2			(1	)
Net current-period other comprehensive income (loss)		(9	)		2			(7	)
Ending balance	$	(26	)	$	(80	)	$	(106	)
Nine Months Ended September 30, 2015
Beginning balance	$	(20	)	$	(66	)	$	(86	)
Other comprehensive income before reclassifications: gains		2			—			2
Amounts reclassified from AOCI(1): (gains) losses		(3	)		3			—
Net current-period other comprehensive income (loss)		(1	)		3			2
Ending balance	$	(21	)	$	(63	)	$	(84	)

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

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

Details About AOCI Components	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Three Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(1	)	Operating revenue
Interest rate contracts		1		Interest and related charges
Foreign currency contracts		(3	)	Other income
		(3	)
Tax		2		Income tax expense
	$	(1	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	2		Other operations and maintenance
		2
Tax		(1	)	Income tax expense
	$	1
Three Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(3	)	Operating revenue
		(3	)
Tax		1		Income tax expense
	$	(2	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	2		Other operations and maintenance
		2
Tax		(1	)	Income tax expense
	$	1
Nine Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(6	)	Operating revenue
Interest rate contracts		2		Interest and related charges
Foreign currency contracts		(1	)	Other income
		(5	)
Tax		2		Income tax expense
	$	(3	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	4		Other operations and maintenance
		4
Tax		(2	)	Income tax expense
	$	2
Nine Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(4	)	Operating revenue
		(4	)
Tax		1		Income tax expense
	$	(3	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	6		Other operations and maintenance
		6
Tax		(3	)	Income tax expense
	$	3

Note 8. Fair Value Measurements

The Companies’ fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in 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.

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

• Foreign currency forward exchange rates

• Credit quality of counterparties and the Companies

• Notional value

• Credit enhancements

• Time value

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. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices, and volumes. For Level 3 fair value measurements, forward market prices, and implied price volatilities are considered unobservable. The unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.

The following table presents Dominion’s quantitative information about Level 3 fair value measurements at September 30, 2016. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input	Range			Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)	$	85	Discounted cash flow	Market price (per Dth)(3)		(2) - 7			—
FTRs		7	Discounted cash flow	Market price (per MWh)(3)		(6) - 6			1
Physical and financial options:
Natural gas		4	Option model	Market price (per Dth)(3)		2 - 7			3
				Price volatility(4)		19% - 46	%		24	%
Total assets	$	96
Liabilities
Physical and financial forwards and futures:
Natural gas(2)	$	4	Discounted cash flow	Market price (per Dth)(3)		(2) - 4			1
FTRs		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
				Price volatility(4)		30% - 46	%		38	%
Total liabilities	$	7

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

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

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)
Price volatility	Buy	Increase (decrease)	Gain (loss)
Price volatility	Sell	Increase (decrease)	Loss (gain)

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Recurring Fair Value Measurements

Dominion

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

	Level 1		Level 2		Level 3		Total
(millions)
At September 30, 2016
Assets
Derivatives:
Commodity	$	—	$	172	$	96	$	268
Interest rate		—		19		—		19
Foreign currency		—		8		—		8
Investments(1):
Equity securities:
United States:
Large cap		2,712		—		—		2,712
REIT		67		—		—		67
Other		6		—		—		6
Non-United States:
Large cap		10		—		—		10
Fixed income:
Corporate debt instruments		—		518		—		518
United States Treasury securities and agency debentures		438		231		—		669
State and municipal		—		372		—		372
Other		—		109		—		109
Cash equivalents and other		8		—		—		8
Total assets	$	3,241	$	1,429	$	96	$	4,766
Liabilities
Derivatives:
Commodity	$	—	$	104	$	7	$	111
Interest rate		—		307		—		307
Foreign currency		—		4		—		4
Total liabilities	$	—	$	415	$	7	$	422

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	Level 1		Level 2		Level 3		Total
(millions)
At December 31, 2015
Assets
Derivatives:
Commodity	$	1	$	249	$	114	$	364
Interest rate		—		24		—		24
Investments(1):
Equity securities:
United States:
Large cap		2,547		—		—		2,547
REIT		63		—		—		63
Other		5		—		—		5
Non-United States:
Large cap		10		—		—		10
Fixed income:
Corporate debt instruments		—		437		—		437
United States Treasury securities and agency debentures		458		201		—		659
State and municipal		—		376		—		376
Other		—		100		—		100
Cash equivalents and other		2		2		—		4
Total assets	$	3,086	$	1,389	$	114	$	4,589
Liabilities
Derivatives:
Commodity	$	—	$	141	$	19	$	160
Interest rate		—		183		—		183
Total liabilities	$	—	$	324	$	19	$	343

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

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

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

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	Operating Revenue		Electric Fuel and Other Energy- Related Purchases			Total
(millions)
Three Months Ended September 30, 2016
Total gains (losses) included in earnings	$	—	$	(7	)	$	(7	)
Three Months Ended September 30, 2015
Total gains (losses) included in earnings	$	—	$	(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
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	$	(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

Virginia Power

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at September 30, 2016. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input	Range			Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)	$	81	Discounted cash flow	Market price (per Dth)(3)		(2) - 7			—
FTRs		7	Discounted cash flow	Market price (per MWh)(3)		(6) - 6			1
Physical and financial options:
Natural gas		2	Option model	Market price (per Dth)(3)		2 - 7			3
				Price volatility(4)		19% - 33	%		24	%
Total assets	$	90
Liabilities
Physical and financial forwards and futures:
FTRs	$	2	Discounted cash flow	Market price (per MWh)(3)		(11) - 6			1
Total liabilities	$	2

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

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

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)
Price volatility	Buy	Increase (decrease)	Gain (loss)
Price volatility	Sell	Increase (decrease)	Loss (gain)

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

	Level 1		Level 2		Level 3		Total
(millions)
At September 30, 2016
Assets
Derivatives:
Commodity	$	—	$	26	$	90	$	116
Interest rate		—		2		—		2
Investments(1):
Equity securities:
United States large cap		1,183		—		—		1,183
REIT		67		—		—		67
Fixed income:
Corporate debt instruments		—		298		—		298
United States Treasury securities and agency debentures		144		107		—		251
State and municipal		—		174		—		174
Other		—		29		—		29
Total assets	$	1,394	$	636	$	90	$	2,120
Liabilities
Derivatives:
Commodity	$	—	$	22	$	2	$	24
Interest rate		—		267		—		267
Total liabilities	$	—	$	289	$	2	$	291
At December 31, 2015
Assets
Derivatives:
Commodity	$	—	$	13	$	101	$	114
Interest rate		—		13		—		13
Investments(1):
Equity securities:
United States large cap		1,100		—		—		1,100
REIT		63		—		—		63
Fixed income:
Corporate debt instruments		—		238		—		238
United States Treasury securities and agency debentures		180		79		—		259
State and municipal		—		175		—		175
Other		—		34		—		34
Total assets	$	1,343	$	552	$	101	$	1,996
Liabilities
Derivatives:
Commodity	$	—	$	19	$	8	$	27
Interest rate		—		59		—		59
Total liabilities	$	—	$	78	$	8	$	86

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

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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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
(millions)
Beginning balance	$	125		$	73		$	93		$	102
Total realized and unrealized gains (losses):
Included in earnings		(7	)		(10	)		(24	)		(1	)
Included in regulatory assets/liabilities		(37	)		47			(5	)		18
Settlements		7			10			24			1
Ending balance	$	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 nine months ended 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 nine months ended September 30, 2016 and 2015.

Dominion Gas

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

	Level 1		Level 2		Level 3		Total
(millions)
At September 30, 2016
Assets
Commodity	$	—	$	6	$	—	$	6
Foreign currency		—		8		—		8
Total Assets	$	—	$	14	$	—	$	14
Liabilities
Commodity	$	—	$	2	$	—	$	2
Foreign currency		—		4		—		4
Total liabilities	$	—	$	6	$	—	$	6
At December 31, 2015
Assets
Commodity	$	—	$	5	$	6	$	11
Total Assets	$	—	$	5	$	6	$	11
Liabilities
Interest rate	$	—	$	14	$	—	$	14
Total liabilities	$	—	$	14	$	—	$	14

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

Fair Value of Financial Instruments

Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, customer, 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:

	September 30, 2016				December 31, 2015
	Carrying     Amount		Estimated Fair     Value(1)		Carrying     Amount		Estimated Fair     Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	26,287	$	29,077	$	21,873	$	23,210
Junior subordinated notes(3)		2,980		3,030		1,340		1,192
Remarketable subordinated notes(3)		2,371		2,392		2,080		2,129
Virginia Power
Long-term debt, including securities due within one year(3)	$	9,642	$	11,259	$	9,368	$	10,400
Dominion Gas
Long-term debt, including securities due within one year(4)	$	3,945	$	4,139	$	3,269	$	3,299

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2) Carrying amount includes amounts which represent the unamortized debt issuance costs, discount and/or premium, and foreign currency remeasurement adjustments. At September 30, 2016 and December 31, 2015, includes the valuation of certain fair value hedges associated with fixed rate debt of $14 million and $7 million, respectively.

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

(4) Carrying amount includes amounts which represent the unamortized debt issuance costs, discount and/or premium, and foreign currency remeasurement adjustments.

Note 9. Derivatives and Hedge Accounting Activities

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

41

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.

Dominion

Balance Sheet Presentation

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

	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
(millions)
Commodity contracts:
Over-the-counter	$	173	$	—	$	173	$	217	$	—	$	217
Exchange		88		—		88		138		—		138
Interest rate contracts:
Over-the-counter		19		—		19		24		—		24
Foreign currency contracts:
Over-the-counter		8		—		8		—		—		—
Total derivatives, subject to a master netting or similar arrangement		288		—		288		379		—		379
Total derivatives, not subject to a master netting or similar arrangement		7		—		7		9		—		9
Total	$	295	$	—	$	295	$	388	$	—	$	388

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			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

	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
(millions)
Commodity contracts:
Over-the-counter	$	43	$	—	$	43	$	70	$	—	$	70
Exchange		63		—		63		82		—		82
Interest rate contracts:
Over-the-counter		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	$	422	$	—	$	422	$	343	$	—	$	343

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			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 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	$	43	$	20	$	—	$	23	$	70	$	37	$	—	$	33
Exchange		63		63		—		—		82		82		—		—
Interest rate contracts:
Over-the-counter		307		10		—		297		183		22		—		161
Foreign currency contracts:
Over-the-counter		4		4		—		—		—		—		—		—
Total	$	417	$	97	$	—	$	320	$	335	$	141	$	—	$	194

Volumes

The following table presents the volume of Dominion’s derivative activity at 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
Natural Gas (bcf):
Fixed price(1)		104		23
Basis		261		626
Electricity (MWh):
Fixed price		8,274,639		659,440
FTRs		72,352,190		—
Liquids (Gal)(2)		39,269,554		—
Interest rate(3)	$	2,200,000,000	$	1,600,000,000
Foreign currency(3)(4)	$	—	$	280,000,000

(1) Includes options.

(2) Includes NGLs and oil.

(3) Maturity is determined based on final settlement period.

(4) Euro equivalent volumes are €250,000,000.

Ineffectiveness and AOCI

For the three and nine months ended 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.

44

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

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(2	)	$	(2	)		39 months
Electricity		44			42			15 months
Other		(1	)		(1	)		6 months
Interest rate		(304	)		(26	)		378 months
Foreign currency		2			—			117 months
Total	$	(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.

45

Fair Value and Gains and Losses on Derivative Instruments

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

	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At September 30, 2016
ASSETS
Current Assets
Commodity	$	59	$	105	$	164
Interest rate		9		—		9
Total current derivative assets(1)		68		105		173
Noncurrent Assets
Commodity		4		100		104
Interest rate		10		—		10
Foreign currency		8		—		8
Total noncurrent derivative assets(2)		22		100		122
Total derivative assets	$	90	$	205	$	295
LIABILITIES
Current Liabilities
Commodity	$	22	$	78	$	100
Interest rate		182		—		182
Foreign currency		4		—		4
Total current derivative liabilities(3)		208		78		286
Noncurrent Liabilities
Commodity		1		10		11
Interest rate		125		—		125
Total noncurrent derivative liabilities(4)		126		10		136
Total derivative liabilities	$	334	$	88	$	422
At December 31, 2015
ASSETS
Current Assets
Commodity	$	101	$	151	$	252
Interest rate		3		—		3
Total current derivative assets(1)		104		151		255
Noncurrent Assets
Commodity		3		109		112
Interest rate		21		—		21
Total noncurrent derivative assets(2)		24		109		133
Total derivative assets	$	128	$	260	$	388
LIABILITIES
Current Liabilities
Commodity	$	32	$	116	$	148
Interest rate		164		—		164
Total current derivative liabilities(3)		196		116		312
Noncurrent Liabilities
Commodity		—		12		12
Interest rate		19		—		19
Total noncurrent derivative liabilities(4)		19		12		31
Total derivative liabilities	$	215	$	128	$	343

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

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

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

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

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) (1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended September 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	64
Purchased gas					(1	)
Electric fuel and other energy-related purchases					(1	)
Total commodity	$	7		$	62		$	—
Interest rate(3)		3			(10	)		(16	)
Foreign currency(4)		12			3			—
Total	$	22		$	55		$	(16	)
Three Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	87
Purchased gas					(2	)
Total commodity	$	64		$	85		$	—
Interest rate(3)		(71	)		(2	)		(69	)
Total	$	(7	)	$	83		$	(69	)
Nine Months Ended September 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	266
Purchased gas					(9	)
Electric fuel and other energy-related purchases					(8	)
Total commodity	$	193		$	249		$	—
Interest rate(3)		(107	)		(21	)		(258	)
Foreign currency(4)		4			1			—
Total	$	90		$	229		$	(258	)
Nine Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	103
Purchased gas					(9	)
Total commodity	$	117		$	94		$	3
Interest rate(3)		(72	)		(7	)		(27	)
Total	$	45		$	87		$	(24	)

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

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

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

(4) Amounts recorded in Dominion’s Consolidated Statements of Income are classified in other income.

47

	Amount of Gain (Loss) Recognized in Income on  Derivatives(1)
	Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives Not Designated as Hedging Instruments	2016			2015			2016			2015
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue	$	25		$	2		$	19		$	20
Purchased gas		(21	)		(3	)		(14	)		(12	)
Electric fuel and other energy-related purchases		(12	)		(4	)		(43	)		5
Interest rate(2)		—			(1	)		—			(1	)
Total	$	(8	)	$	(6	)	$	(38	)	$	12

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

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

Virginia Power

Balance Sheet Presentation

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

	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
(millions)
Commodity contracts:
Over-the-counter	$	88	$	—	$	88	$	101	$	—	$	101
Interest rate contracts:
Over-the-counter		2		—		2		13		—		13
Total derivatives, subject to a master netting or similar arrangement		90		—		90		114		—		114
Total derivatives, not subject to a master netting or similar arrangement		28		—		28		13		—		13
Total	$	118	$	—	$	118	$	127	$	—	$	127

			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	$	88	$	2	$	—	$	86	$	101	$	3	$	—	$	98
Interest rate contracts:
Over-the-counter		2		—		—		2		13		10		—		3
Total	$	90	$	2	$	—	$	88	$	114	$	13	$	—	$	101

48

	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
(millions)
Commodity contracts:
Over-the-counter	$	9	$	—	$	9	$	5	$	—	$	5
Interest rate contracts:
Over-the-counter		267		—		267		59		—		59
Total derivatives, subject to a master netting or similar arrangement		276		—		276		64		—		64
Total derivatives, not subject to a master netting or similar arrangement		15		—		15		22		—		22
Total	$	291	$	—	$	291	$	86	$	—	$	86

			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 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	$	9	$	2	$	—	$	7	$	5	$	3	$	—	$	2
Interest rate contracts:
Over-the-counter		267		—		—		267		59		10		—		49
Total	$	276	$	2	$	—	$	274	$	64	$	13	$	—	$	51

Volumes

The following table presents the volume of Virginia Power’s derivative activity at 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
Natural Gas (bcf):
Fixed price(1)		32		12
Basis		126		558
Electricity (MWh):
FTRs		70,978,901		—
Interest rate	$	1,200,000,000	$	600,000,000

(1) Includes options.

Ineffectiveness and AOCI

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

49

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 September 30, 2016:

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

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 interest rates.

50

Fair Value and Gains and Losses on Derivative Instruments

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

	Fair Value – Derivatives under Hedge Accounting		Fair Value –Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At September 30, 2016
ASSETS
Current Assets
Commodity	$	—	$	25	$	25
Interest rate		2		—		2
Total current derivative assets(1)		2		25		27
Noncurrent Assets
Commodity		—		91		91
Total noncurrent derivative assets(2)		—		91		91
Total derivative assets	$	2	$	116	$	118
LIABILITIES
Current Liabilities
Commodity	$	—	$	19	$	19
Interest rate		142		—		142
Total current derivative liabilities(3)		142		19		161
Noncurrent Liabilities
Commodity		—		5		5
Interest rate		125		—		125
Total noncurrent derivatives liabilities (4)		125		5		130
Total derivative liabilities	$	267	$	24	$	291
At December 31, 2015
ASSETS
Current Assets
Commodity	$	—	$	18	$	18
Total current derivative assets(1)		—		18		18
Noncurrent Assets
Commodity		—		96		96
Interest rate		13		—		13
Total noncurrent derivative assets(2)		13		96		109
Total derivative assets	$	13	$	114	$	127
LIABILITIES
Current Liabilities
Commodity	$	—	$	23	$	23
Interest rate		57		—		57
Total current derivative liabilities(3)		57		23		80
Noncurrent Liabilities
Commodity		—		4		4
Interest rate		2		—		2
Total noncurrent derivative liabilities(4)		2		4		6
Total derivative liabilities	$	59	$	27	$	86

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

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

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

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

51

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended September 30, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(2	)	$	—		$	(16	)
Total	$	(2	)	$	—		$	(16	)
Three Months Ended September 30, 2015
Derivative type and location of gains (losses):
Interest rate(3)	$	(9	)	$	—		$	(69	)
Total	$	(9	)	$	—		$	(69	)
Nine Months Ended September 30, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(26	)	$	(1	)	$	(258	)
Total	$	(26	)	$	(1	)	$	(258	)
Nine Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Total commodity	$	—		$	(1	)	$	3
Interest rate(3)		(4	)		—			(27	)
Total	$	(4	)	$	(1	)	$	(24	)

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

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

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

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

(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.

(2) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.

52

Dominion Gas

Balance Sheet Presentation

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

	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
(millions)
Commodity contracts:
Over-the-counter	$	6	$	—	$	6	$	11	$	—	$	11
Foreign currency contracts:
Over-the-counter		8		—		8		—		—		—
Total derivatives, subject to a master netting or similar arrangement	$	14	$	—	$	14	$	11	$	—	$	11

			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	$	6	$	1	$	—	$	5	$	11	$	—	$	—	$	11
Foreign currency contracts:
Over-the-counter		8		4		—		4		—		—		—		—
Total	$	14	$	5	$	—	$	9	$	11	$	—	$	—	$	11

	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
(millions)
Commodity contracts:
Over-the-counter	$	2	$	—	$	2	$	—	$	—	$	—
Interest rate contracts:
Over-the-counter		—		—		—		14		—		14
Foreign currency contracts:
Over-the-counter		4		—		4		—		—		—
Total derivatives, subject to a master netting or similar arrangement	$	6	$	—	$	6	$	14	$	—	$	14

53

			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 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	$	2	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Interest rate contracts:
Over-the-counter		—		—		—		—		14		—		—		14
Foreign currency contracts:
Over-the-counter		4		4		—		—		—		—		—		—
Total	$	6	$	5	$	—	$	1	$	14	$	—	$	—	$	14

Volumes

The following table presents the volume of Dominion Gas’ derivative activity at 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
Natural Gas (bcf):
Fixed price		6		—
Basis		6		—
NGLs (Gal)		33,095,554		—
Foreign currency(1)	$	—	$	280,000,000

(1) Maturity is determined based on final settlement period. Euro equivalent volumes are €250,000,000.

Ineffectiveness and AOCI

For the three and nine months ended 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 September 30, 2016:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
NGLs	$	(1	)	$	(1	)		6 months
Interest rate		(27	)		(2	)		339 months
Foreign currency		2			—			117 months
Total	$	(26	)	$	(3	)

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 rates.

54

Fair Value and Gains and Losses on Derivative Instruments

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
(millions)
At September 30, 2016
ASSETS
Current Assets
Commodity	$	1	$	5	$	6
Total current derivative assets(1)		1		5		6
Noncurrent Assets
Foreign currency		8		—		8
Total noncurrent derivative assets(2)		8		—		8
Total derivative assets	$	9	$	5	$	14
LIABILITIES
Current Liabilities
Commodity	$	2	$	—	$	2
Foreign currency		4		—		4
Total current derivative liabilities(3)		6		—		6
Total derivative liabilities	$	6	$	—	$	6
At December 31, 2015
ASSETS
Current Assets
Commodity	$	10	$	—	$	10
Total current derivative assets(1)		10		—		10
Noncurrent Assets
Commodity		1		—		1
Total noncurrent derivatives assets(2)		1		—		1
Total derivative assets	$	11	$	—	$	11
LIABILITIES
Noncurrent Liabilities
Interest rate	$	14	$	—	$	14
Total noncurrent derivative liabilities(4)		14		—		14
Total derivative liabilities	$	14	$	—	$	14

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

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

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

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

55

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income
(millions)
Three Months Ended September 30, 2016
Derivative Type and Location of Gains (Losses):
Commodity:
Operating revenue				$	1
Total commodity	$	—		$	1
Interest rate(2)		—			(1	)
Foreign currency(3)		12			3
Total	$	12		$	3
Three Months Ended September 30, 2015
Derivative Type and Location of Gains (Losses):
Commodity:
Operating revenue				$	3
Total commodity	$	11		$	3
Interest rate(2)		(7	)		—
Total	$	4		$	3
Nine Months Ended September 30, 2016
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	6
Total commodity	$	(7	)	$	6
Interest rate(2)		(8	)		(2	)
Foreign currency(3)		4			1
Total	$	(11	)	$	5
Nine Months Ended September 30, 2015
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	4
Total commodity	$	10		$	4
Interest rate(2)		(8	)		—
Total	$	2		$	4

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

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

(3) Amounts recorded in Dominion Gas’ Consolidated Statements of Income are classified in other income.

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

56

Note 10. Investments

Dominion

Equity and Debt Securities

Rabbi Trust Securities

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

Decommissioning Trust Securities

Dominion holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below:

	Amortized Cost		Total Unrealized Gains(1)		Total Unrealized Losses(1)			Fair Value
(millions)
At September 30, 2016
Marketable equity securities:
United States large cap	$	1,361	$	1,312	$	—		$	2,673
REIT		59		8		—			67
Marketable debt securities:
Corporate bonds		493		26		(1	)		518
United States Treasury securities and agency debentures		645		21		—			666
State and municipal		306		27		—			333
Other		89		—		—			89
Cost method investments		69		—		—			69
Cash equivalents and other(2)		12		—		—			12
Total	$	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
REIT		59		4		—			63
Marketable debt securities:
Corporate bonds		433		11		(7	)		437
United States Treasury securities and agency debentures		654		8		(4	)		658
State and municipal		312		22		—			334
Other		99		—		—			99
Cost method investments		70		—		—			70
Cash equivalents and other(2)		14		—		—			14
Total	$	2,936	$	1,258	$	(11	)(3)	$	4,183

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

(2) Includes pending sales of securities of $9 million and $12 million at September 30, 2016 and December 31, 2015, respectively.

(3) The fair value of securities in an unrealized loss position was $156 million and $592 million at September 30, 2016 and December 31, 2015, respectively.

57

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at 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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Proceeds from sales	$	300	$	357	$	1,009	$	937
Realized gains(1)		40		65		102		165
Realized losses(1)		9		40		43		69

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

Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
(millions)
Total other-than-temporary impairment losses(1)	$	9		$	29		$	34		$	55
Losses recorded to the nuclear decommissioning trust regulatory liability		(4	)		(10	)		(15	)		(21	)
Losses recognized in other comprehensive income (before taxes)		—			(3	)		(1	)		(7	)
Net impairment losses recognized in earnings	$	5		$	16		$	18		$	27

(1) Amounts include other-than-temporary impairment losses for debt securities of less than $1 million and $3 million for the three months ended September 30, 2016 and 2015, respectively, and $2 million and $7 million for the nine months ended September 30, 2016 and 2015, respectively.

58

Virginia Power

Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below:

	Amortized Cost		Total Unrealized Gains(1)		Total Unrealized Losses(1)			Fair Value
(millions)
At September 30, 2016
Marketable equity securities:
United States large cap	$	606	$	576	$	—		$	1,182
REIT		59		8		—			67
Marketable debt securities:
Corporate bonds		285		13		—			298
United States Treasury securities and agency debentures		246		5		—			251
State and municipal		158		15		—			173
Other		29		—		—			29
Cost method investments		69		—		—			69
Cash equivalents and other(2)		5		—		—			5
Total	$	1,457	$	617	$	—	(3)	$	2,074
At December 31, 2015
Marketable equity securities:
United States large cap	$	574	$	525	$	—		$	1,099
REIT		59		4		—			63
Marketable debt securities:
Corporate bonds		237		5		(4	)		238
United States Treasury securities and agency debentures		260		1		(2	)		259
State and municipal		162		13		(1	)		174
Other		34		—		—			34
Cost method investments		70		—		—			70
Cash equivalents and other(2)		8		—		—			8
Total	$	1,404	$	548	$	(7	)(3)	$	1,945

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

(2) Includes pending sales of securities of $4 million and $8 million at September 30, 2016 and December 31, 2015, respectively.

(3) The fair value of securities in an unrealized loss position was $91 million and $281 million at September 30, 2016 and December 31, 2015, respectively.

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

	Amount
(millions)
Due in one year or less	$	51
Due after one year through five years		228
Due after five years through ten years		202
Due after ten years		270
Total	$	751

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Proceeds from sales	$	131	$	198	$	478	$	407
Realized gains(1)		18		45		48		82
Realized losses(1)		4		18		21		33

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

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

Equity Method Investments

Dominion

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

Iroquois

Dominion Gas’ equity earnings totaled $14 million and $17 million for the nine months ended September 30, 2016 and 2015, respectively. Dominion Gas received distributions from this investment of $17 million and $26 million for the nine months ended September 30, 2016 and 2015, respectively. At September 30, 2016 and December 31, 2015, the carrying amount of Dominion Gas’ investment of $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, included in other income in Dominion Gas’ Consolidated Statements of Income.

Note 11. Regulatory Assets and Liabilities

Regulatory assets and liabilities include the following:

	September 30, 2016		December 31, 2015
(millions)
Dominion
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	101	$	90
Deferred nuclear refueling outage costs(2)		60		75
Deferred cost of fuel used in electric generation(3)		3		111
Other		86		75
Regulatory assets-current(4)		250		351
Unrecognized pension and other postretirement benefit costs(5)		981		1,015
Derivatives(6)		366		110
Deferred rate adjustment clause costs(1)		271		295
PJM transmission rates(7)		192		192
Income taxes recoverable through future rates(8)		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

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	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)		21		20
Other		82		65
Regulatory assets-non-current(13)		469		449
Total regulatory assets	$	491	$	472
Regulatory liabilities:
PIPP(9)	$	26	$	46
Other		13		9
Regulatory liabilities-current(10)		39		55
Provision for future cost of removal and AROs(11)		173		170
Other		44		31
Regulatory liabilities-non-current(14)		217		201
Total regulatory liabilities	$	256	$	256

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

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

Note 12. Regulatory Matters

Regulatory Matters Involving Potential Loss Contingencies

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

FERC - Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Dominion’s merchant generators sell electricity in the 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

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wholesale market. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.

Rates

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

In March 2010, 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.

PJM Transmission Rates

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

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015 and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016 and June 30, 2016.

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Virginia Regulation

Virginia Fuel Expenses

In May 2016, Virginia Power submitted its annual fuel factor to the Virginia Commission to recover an estimated $1.4 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 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. In October 2016, the Virginia Commission approved Virginia Power’s proposed fuel rate.

Rate Adjustment Clauses

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

• The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In October 2016, Virginia Power proposed a $134 million revenue requirement for the rate year beginning September 1, 2017, which represents a $14 million increase over the previous year. This case is pending.

• The Virginia Commission previously approved Rider US-2 in conjunction with the Scott Solar, Whitehouse, and Woodland solar facilities. In October 2016, Virginia Power proposed a $10 million revenue requirement for the rate year beginning September 1, 2017, which represents a $6 million increase over the previous year. This case is pending.

• The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2016, Virginia Power proposed a total revenue requirement of $45 million for the rate year beginning July 1, 2017. Virginia Power also proposed two new energy efficiency programs for Virginia Commission approval with a requested five-year cost cap of $178 million for those programs. Virginia Power further proposed to extend an existing energy efficiency program for an additional two years under current funding, and an existing peak shaving program for an additional five years with an additional $5 million cost cap. This case is pending.

• Virginia Power previously filed for Virginia Commission approval of a revised Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by prior Virginia legislation. In August 2016, the Virginia Commission approved a net $20 million revenue requirement and a 9.6% ROE for the rate year beginning September 1, 2016, and an additional $2 million in credits for each of the 2017-2018 and 2018-2019 rate years. The order limited the total investment in Phase One of Virginia Power’s proposed program to $140 million, with $123 million recoverable through Rider U.

Electric Transmission Project

Virginia Power previously filed an application with the Virginia Commission for a CPCN to construct and operate in Loudoun County, Virginia, a new approximately 230 kV Poland Road substation, and a new approximately four mile overhead 230 kV double circuit transmission line between the existing 230 kV Loudoun-Brambleton line and the Poland Road substation. In August 2016, the Virginia Commission granted a CPCN to construct and operate the project along a revised route.

North Anna

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.

Requests by BREDL for a contested NRC hearing on Virginia Power’s COL application have been dismissed, and in September 2016, the United States Court of Appeals for the District of Columbia dismissed with prejudice petitions for judicial review that BREDL and other organizations had filed challenging the NRC’s reliance on a rule generically assessing the environmental impacts of continued onsite storage of spent nuclear fuel in various licensing proceedings, including Virginia Power’s COL proceeding. This dismissal followed the Court’s June 2016 decision in New York v. NRC, upholding the NRC’s continued storage rule and August 2016 denial of requests for rehearing en 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.

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North Carolina Regulation

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 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 North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $36 million decrease to the fuel component of its electric rates for the rate year beginning January 1, 2017. This case is pending.

Ohio Regulation

PIR

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In 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 annual capital expenditures to $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.

PSMP

In November 2016, the Ohio Commission approved East Ohio’s request to defer the operation and maintenance costs associated with implementing PSMP of up to $15 million per year.

West Virginia Regulation

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. In September 2016, Hope reached a settlement with all parties to the case agreeing to new PREP customer rates, for the year beginning November 1, 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.

FERC - Gas

In August 2016, Dominion Gas received FERC authorization to construct and operate the Leidy South Project facilities. Service under the 20-year contracts is expected to commence in the fourth quarter of 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.

Note 13. Variable Interest Entities

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

Dominion

As of September 30, 2016, Dominion owns the general partner interest and 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 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

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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

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 and Dominion Gas

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

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 $320 million as of September 30, 2016. Virginia Power paid $37 million and $52 million for electric capacity and $11 million and $17 million for electric energy to these entities in the three months ended 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.

Dominion Gas

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

Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of $80 million and $31 million for the three months ended September 30, 2016, $73 million and $27 million for the three months ended September 30, 2015, $268 million and $95 million for the nine months ended September 30, 2016 and $239 million and $85 million for the nine months ended 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.

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Note 14. Significant Financing Transactions

Credit Facilities and Short-term Debt

The Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.

Dominion

At 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
(millions)
Joint revolving credit facility(1)	$	5,000	$	3,073	$	—	$	1,927
Joint revolving credit facility(1)		500		—		60		440
Revolving multi-year credit facility(2)		500		24		—		476
Revolving 364-day credit facility(2)		250		—		—		250
Total	$	6,250	$	3,097	$	60	$	3,093

(1) In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

(2) These Dominion Questar facilities were terminated in October 2016.

Virginia Power

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 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
(millions)
Joint revolving credit facility(1)	$	5,000	$	965	$	—
Joint revolving credit facility(1)		500		—		—
Total	$	5,500	$	965	$	—

(1) The full amount of the facilities is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion and Dominion Gas. Sub-limits for Virginia Power are set within the facility limit but can be changed at the option of the Companies multiple times per year. At September 30, 2016, the aggregate sub-limit for Virginia Power was $2.0 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion. In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

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 September 30, 2016, this facility supports $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

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.

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At 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
(millions)
Joint revolving credit facility(1)	$	1,000	$	60	$	—
Joint revolving credit facility(1)		500		—		—
Total	$	1,500	$	60	$	—

(1) A maximum of a combined $1.5 billion of the facilities is available to Dominion Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion and Virginia Power. Sub-limits for Dominion Gas are set within the facility limit but can be changed at the option of the Companies multiple times per year. In September 2016, the aggregate sub-limit for Dominion Gas was decreased from $1.0 billion to $750 million. If Dominion Gas has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion. In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

Remarketable Subordinated Notes

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 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.

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Selected information about Dominion’s 2016 Equity Units is presented below:

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

(1) Annual interest rate applies to each of the Series A-1 RSNs and Series A-2 RSNs.

(2) The maturity dates of the $700 million Series A-1 RSNs and $700 million Series A-2 RSNs are August 15, 2021 and August 15, 2024, respectively.

Enhanced Junior Subordinated Notes

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 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.

Long-term Debt

In May 2016, Dominion Gas issued $150 million of private placement 3.8% senior notes that mature in 2031. In June 2016, Dominion Gas issued $250 million of private placement 2.875% senior notes that mature in 2023. Also in June 2016, Dominion Gas issued €250 million of private placement 1.45% 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 $281 million at 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.

Short-term Notes

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.

Issuance of Common Stock

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

In 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 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.

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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 received proceeds of $756 million through a registered underwritten public offering. A portion of the net proceeds was used to finance the Dominion Questar Combination. See Note 3 for more information.

Note 15. Commitments and Contingencies

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

Environmental Matters

The Companies are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

Air

CAA

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.

MATS

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. 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

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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 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.

CAIR

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.

CSAPR

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) 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.

Ozone Standards

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. 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.

NO_x and VOC Emissions

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.

NSPS

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 and Dominion Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.

Methane Emissions

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

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joined the EPA as founding partners in this program for its distribution companies, East Ohio and Hope, DTI and 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 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.

Climate Change Legislation and Regulation

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 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. In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to 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 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 final action on this rulemaking, the Companies cannot predict the impact to their financial 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.

Water

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

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power are currently evaluating the need or potential for 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.

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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.

Solid and Hazardous Waste

The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the 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. The Companies do not believe 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. In September 2016, the United States, on behalf of the EPA, lodged a 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 between the EPA and a number of parties, including Virginia Power. The Consent Decree identifies Virginia Power as a non-performing cash-out party to the settlement and, once approved by the court, would resolve Virginia Power’s alleged liability under CERCLA with respect to the site, including liability pursuant to the UAO. The ultimate outcome of this matter depends on the approval of the Consent Decree by the Court, and cannot be predicted at this time; however, this matter is not expected to have a material effect on Virginia Power.

Dominion has determined that it is associated with 19 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion Gas. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which the Companies are associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.

See below for discussion on ash pond and landfill closure costs.

Other Legal Matters

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

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Appalachian Gateway

Pipeline Contractor Litigation

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.

Gas Producers Litigation

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.

Ash Pond and Landfill Closure Costs

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 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

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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. In November 2016, the court dismissed the remaining appeal. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the increased obligation in 2015.

Cove Point

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 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.

FERC

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.

Greensville County

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.

Nuclear Matters

In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as 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

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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.

Guarantees, Surety Bonds and Letters of Credit

Dominion

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

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	27	$	27
Commodity transactions(3)		2,081		874
Nuclear obligations(4)		169		94
Cove Point(5)		1,900		—
Solar(6)		1,847		539
Other(7)		783		60
Total	$	6,807	$	1,594

(1) Represents the estimated portion of the guarantee’s stated limit that is utilized as of September 30, 2016 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount.

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

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

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

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

(6) Includes guarantees related to solar projects including guarantees that do not have stated limits. Also includes guarantees related to solar projects entered into by DEI on behalf of certain subsidiaries.

(7) Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of September 30, 2016, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $36 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits.

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

Note 16. Credit Risk

The Companies’ accounting policies for credit risk are discussed in Note 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015.

At September 30, 2016, Dominion’s credit exposure related to energy marketing and price risk management activities totaled $96 million. Of this amount, investment grade counterparties, including those internally rated, represented 70%. No single counterparty, whether investment grade or non-investment grade, exceeded $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.

Credit-Related Contingent Provisions

The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of September 30, 2016 and December 31, 2015, Dominion would have been required to post an additional $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 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 September 30, 2016 and December 31, 2015 was $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 September 30, 2016 and December 31, 2015. See Note 9 for further information about derivative instruments.

Note 17. Related-Party Transactions

Virginia Power and Dominion Gas engage in related-party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s and Dominion Gas’ receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power and Dominion Gas are included in Dominion’s consolidated federal income tax return. Dominion’s transactions with equity method investments are described in Note 10. A discussion of significant related-party transactions follows.

Virginia Power

Transactions with Affiliates

Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity physical forwards and options, to manage commodity price risks associated with purchases of natural gas. As of September 30, 2016, Virginia Power’s derivative assets and liabilities with affiliates were $28 million and $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 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 $376 million and $316 million, respectively, and amounts due from Dominion at September 30, 2016 and December 31, 2015 included in other deferred charges and other assets were $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.

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Presented below are Virginia Power’s significant transactions with DRS and other affiliates:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Commodity purchases from affiliates	$	172	$	123	$	416	$	469
Services provided by affiliates(1)		105		96		347		313
Services provided to affiliates		5		5		17		15

(1) Includes capitalized expenditures of $32 million for both the three months ended September 30, 2016 and 2015, and $109 million and $105 million for the nine months ended September 30, 2016 and 2015, respectively.

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 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 September 30, 2016 and December 31, 2015. Interest charges related to Virginia Power’s borrowings from Dominion were immaterial for the three and nine months ended September 30, 2016 and 2015.

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

Dominion Gas

Transactions with Related Parties

Dominion Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Gas provides transportation and storage services to affiliates. Dominion Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of 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 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 $686 million and $652 million, respectively, and amounts due to Dominion at 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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Purchases of natural gas and transportation and storage services from affiliates	$	2	$	3	$	7	$	7
Sales of natural gas and transportation and storage services to affiliates		16		17		51		52
Services provided by related parties(1)		36		30		108		99
Services provided to related parties (2)		34		30		94		75

(1) Includes capitalized expenditures of $13 million and $16 million for the three months ended September 30, 2016 and 2015, respectively, and $37 million and $40 million for the nine months ended September 30, 2016 and 2015, respectively.

(2) Amounts primarily attributable to Atlantic Coast Pipeline.

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

	September 30, 2016		December 31, 2015
(millions)
Other receivables(1)	$	9	$	7
Customer receivables from related parties		1		4
Imbalances receivable from affiliates(2)		1		1
Affiliated notes receivable(3)		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 September 30, 2016 and December 31, 2015, respectively. Interest charges related to Dominion Gas’ total borrowings from Dominion were immaterial for the three and nine months ended September 30, 2016 and 2015.

Note 18. Employee Benefit Plans

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 nine months ended 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.

Dominion

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

	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016			2015
(millions)
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	$	87		$	95		$	23		$	30
Interest cost		234			215			50			50
Expected return on plan assets		(419	)		(398	)		(87	)		(88	)
Amortization of prior service cost (credit)		1			1			(23	)		(20	)
Amortization of net actuarial loss		84			120			5			4
Net periodic benefit cost (credit)	$	(13	)	$	33		$	(32	)	$	(24	)

Plan Amendment and Remeasurement

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.

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Employer Contributions

During the nine months ended 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

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
	2016			2015			2016			2015
(millions)
Three Months Ended September 30,
Service cost	$	3		$	4		$	1		$	2
Interest cost		7			7			3			3
Expected return on plan assets		(33	)		(31	)		(5	)		(6	)
Amortization of net actuarial loss		3			5			—			1
Net periodic benefit credit	$	(20	)	$	(15	)	$	(1	)	$	—
Nine Months Ended September 30,
Service cost	$	10		$	11		$	4		$	5
Interest cost		22			21			10			10
Expected return on plan assets		(100	)		(94	)		(17	)		(18	)
Amortization of net actuarial loss		10			15			1			2
Net periodic benefit credit	$	(58	)	$	(47	)	$	(2	)	$	(1	)

Employer Contributions

During the nine months ended 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.

Note 19. Operating Segments

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:

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

(1) Includes remaining producer services activities for Dominion.

(2) As a result of Dominion’s decision to realign its business units effective for 2015 year-end reporting, nonregulated retail energy marketing operations were moved from the Dominion Generation segment to the Dominion Energy segment.

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

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Dominion

The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued or sold. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources.

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

• A $59 million ($36 million after-tax) charge related to an organizational design initiative, attributable to:

• DVP ($5 million after-tax);

• Dominion Energy ($12 million after-tax); and

• Dominion Generation ($19 million after-tax); partially offset by

• A $29 million ($18 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.

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:

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

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

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

• A $39 million ($25 million after-tax) net gain on investments held in nuclear decommissioning trust funds.

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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
(millions)
Three Months Ended September 30, 2016
Total revenue from external customers	$	614	$	1,947	$	359	$	2		$	210		$	3,132
Intersegment revenue		6		2		205		144			(357	)		—
Total operating revenue		620		1,949		564		146			(147	)		3,132
Net income (loss) attributable to Dominion		139		650		135		(234	)		—			690
Three Months Ended September 30, 2015
Total revenue from external customers	$	539	$	1,892	$	377	$	—		$	163		$	2,971
Intersegment revenue		4		2		159		128			(293	)		—
Total operating revenue		543		1,894		536		128			(130	)		2,971
Net income (loss) attributable to Dominion		125		390		153		(75	)		—			593
Nine Months Ended September 30, 2016
Total revenue from external customers	$	1,682	$	5,204	$	1,235	$	8		$	522		$	8,651
Intersegment revenue		17		7		507		469			(1,000	)		—
Total operating revenue		1,699		5,211		1,742		477			(478	)		8,651
Net income (loss) attributable to Dominion		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

(1) 2015 amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Energy segment.

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

Virginia Power

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

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

• A $33 million ($20 million after-tax) charge related to an organizational design initiative, attributable to:

• DVP ($5 million after-tax); and

• Dominion Generation ($15 million after-tax).

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:

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

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

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

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

	DVP		Dominion Generation		Corporate and Other			Consolidated Total
(millions)
Three Months Ended September 30, 2016
Operating revenue	$	617	$	1,594	$	—		$	2,211
Net income		140		359		4			503
Three Months Ended September 30, 2015
Operating revenue	$	541	$	1,523	$	(6	)	$	2,058
Net income (loss)		125		273		(13	)		385
Nine Months Ended September 30, 2016
Operating revenue	$	1,686	$	4,191	$	—		$	5,877
Net income (loss)		362		699		(15	)		1,046
Nine Months Ended September 30, 2015
Operating revenue	$	1,610	$	4,419	$	(21	)	$	6,008
Net income (loss)		382		618		(100	)		900

Dominion Gas

The Corporate and Other Segment of Dominion Gas primarily includes specific items attributable to Dominion Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance 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 nine months ended September 30, 2016, Dominion Gas reported an after-tax net benefit of $5 million for specific items in the Corporate and Other segment, with after-tax net expense of $7 million attributable to its operating segment. In the nine months ended 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
(millions)
Three Months Ended September 30, 2016
Operating revenue	$	382	$	—		$	382
Net income		77		6			83
Three Months Ended September 30, 2015
Operating revenue	$	365	$	—		$	365
Net income (loss)		113		(2	)		111
Nine Months Ended September 30, 2016
Operating revenue	$	1,181	$	—		$	1,181
Net income (loss)		288		(2	)		286
Nine Months Ended September 30, 2015
Operating revenue	$	1,291	$	—		$	1,291
Net income (loss)		364		(7	)		357

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Contents of MD&A

MD&A consists of the following information:

• Forward-Looking Statements

• Accounting Matters - Dominion

• Dominion

• Results of Operations

• Segment Results of Operations

• Virginia Power

• Results of Operations

• Dominion Gas

• Results of Operations

• Liquidity and Capital Resources - Dominion

• Future Issues and Other Matters - Dominion

Forward-Looking Statements

This report contains statements concerning the Companies’ expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words.

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

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

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

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

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

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

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

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

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

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

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

• Counterparty credit and performance risk;

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

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

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

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• Fluctuations in interest rates or foreign currency exchange rates;

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

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

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

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

• Impacts of acquisitions, including the recently completed Dominion Questar Combination, divestitures, transfers of assets to joint ventures or Dominion Midstream, and retirements of assets based on asset portfolio reviews;

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

• The timing and execution of Dominion Midstream’s growth strategy;

• Changes in rules for regional transmission organizations and independent system operators in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;

• Political and economic conditions, including inflation and deflation;

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

• Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion and Dominion Gas’ pipeline and processing systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;

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

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

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

• Changes in operating, maintenance and construction costs;

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

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

• Adverse outcomes in litigation matters or regulatory proceedings; and

• The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in the Companies’ Annual Report on Form 10-K for the year ended December 31, 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.

Accounting Matters

Critical Accounting Policies and Estimates

As of 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.

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Dominion

Results of Operations

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

	2016		2015		$ Change
(millions, except EPS)
Third Quarter
Net income attributable to Dominion	$	690	$	593	$	97
Diluted EPS		1.10		1.00		0.10
Year-To-Date
Net income attributable to Dominion	$	1,666	$	1,542	$	124
Diluted EPS		2.71		2.60		0.11

Overview

Third Quarter 2016 vs. 2015

Net income attributable to Dominion increased 16%, primarily due to higher renewable energy investment tax credits, an increase in electric utility 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.

Year-To-Date 2016 vs. 2015

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 and transaction and transition costs due to the Dominion Questar Combination.

Analysis of Consolidated Operations

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

	Third Quarter								Year-To-Date
	2016			2015		$ Change			2016		2015		$ Change
(millions)
Operating revenue	$	3,132		$	2,971	$	161		$	8,651	$	9,127	$	(476	)
Electric fuel and other energy-related purchases		606			636		(30	)		1,791		2,180		(389	)
Purchased (excess) electric capacity		(6	)		75		(81	)		107		259		(152	)
Purchased gas		77			85		(8	)		252		446		(194	)
Net revenue		2,455			2,175		280			6,501		6,242		259
Other operations and maintenance		765			564		201			2,133		1,875		258
Depreciation, depletion and amortization		400			355		45			1,112		1,037		75
Other taxes		145			133		12			448		432		16
Other income		63			11		52			189		127		62
Interest and related charges		250			230		20			715		674		41
Income tax expense		230			305		(75	)		561		794		(233	)

An analysis of Dominion’s results of operations follows:

Third Quarter 2016 vs. 2015

Net revenue increased 13%, primarily reflecting:

• A $272 million increase from electric utility operations, primarily reflecting:

• An $81 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($70 million) and the expiration of non-utility generator contracts in 2015 ($16 million);

• An increase from rate adjustment clauses ($78 million); and

• An increase in sales to retail customers from an increase in cooling degree days ($74 million); and

• A $32 million increase due to the Dominion Questar Combination; partially offset by

• A $22 million decrease from merchant generation operations, primarily due to lower realized prices.

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Other operations and maintenance increased 36%, primarily reflecting:

• A $51 million increase due to the Dominion Questar Combination, including $40 million of transaction and transition costs;

• A $50 million increase in salaries, wages and benefits;

• A $47 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields; and

• A $21 million increase due to labor contract renegotiations as well as costs resulting from a union workforce temporary work stoppage.

Depreciation, depletion and amortization increased 13%, primarily due to various expansion projects being placed into service ($32 million) and 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 earnings from equity method investments ($15 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 pre-tax income ($21 million).

Year-To-Date 2016 vs. 2015

Net revenue increased 4%, primarily reflecting:

• A $355 million increase from electric utility operations, primarily reflecting:

• A $147 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($92 million) and the expiration of non-utility generator contracts in 2015 ($56 million);

• An increase from rate adjustment clauses ($129 million); and

• The absence of an $85 million write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015; partially offset by

• A decrease in sales to retail customers from a reduction in cooling and heating degree days ($58 million); and

• A $32 million increase due to the Dominion Questar Combination.

These increases were partially offset by:

• A $61 million decrease from merchant generation operations, primarily due to lower volumes from planned and unplanned outage days ($63 million) and lower realized prices ($34 million), partially offset by additional solar generating facilities placed into service ($27 million);

• A $36 million decrease from regulated natural gas distribution operations, primarily due to a decrease in rate adjustment clause revenue related to low income assistance programs ($33 million) and a decrease in sales to customers due to a reduction in heating degree days ($11 million), partially offset by an increase in AMR and PIR program revenues ($12 million); and

• A $27 million decrease from regulated natural gas transmission operations, primarily due to:

• A $24 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($29 million) and decreased fuel retained ($11 million), partially offset by the acquisition of DCG and related expansion projects ($12 million); and

• A $17 million decrease in NGL activities, due to decreased volumes ($12 million) and prices ($5 million); partially offset by

• A $17 million increase in services performed for Atlantic Coast Pipeline.

Other operations and maintenance increased 14%, primarily reflecting:

• A $78 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields;

• A $58 million increase due to the Dominion Questar Combination, including $47 million of transaction and transition costs;

• Organizational design initiative costs ($64 million);

• A $47 million increase in salaries, wages and benefits;

• A $38 million increase in planned outage costs primarily due to an increase in scheduled outage days at certain merchant generation facilities;

• A $28 million increase in storm damage and service restoration costs;

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• A $21 million increase due to labor contract renegotiations as well as costs resulting from a union workforce temporary work stoppage; and

• A $17 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income.

These increases were partially offset by:

• The absence of a $45 million charge related to ash pond and landfill closure costs at certain utility generation facilities; and

• A $33 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income.

Other income increased 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 expense decreased 29%, primarily due to higher renewable energy investment tax credits ($153 million), lower pre-tax income ($27 million), the impact of a state legislative change ($17 million) and a settlement with a tax authority ($12 million).

Segment Results of Operations

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

	Net Income attributable to Dominion									Diluted EPS
	2016			2015			$ Change			2016			2015			$ Change
(millions, except EPS)
Third Quarter
DVP	$	139		$	125		$	14		$	0.22		$	0.21		$	0.01
Dominion Generation(1)		650			390			260			1.04			0.66			0.38
Dominion Energy(1)		135			153			(18	)		0.21			0.26			(0.05	)
Primary operating segments		924			668			256			1.47			1.13			0.34
Corporate and Other		(234	)		(75	)		(159	)		(0.37	)		(0.13	)		(0.24	)
Consolidated	$	690		$	593		$	97		$	1.10		$	1.00		$	0.10
Year-To-Date
DVP	$	363		$	382		$	(19	)	$	0.59		$	0.64		$	(0.05	)
Dominion Generation(1)		1,066			902			164			1.74			1.52			0.22
Dominion Energy(1)		483			509			(26	)		0.78			0.86			(0.08	)
Primary operating segments		1,912			1,793			119			3.11			3.02			0.09
Corporate and Other		(246	)		(251	)		5			(0.40	)		(0.42	)		0.02
Consolidated	$	1,666		$	1,542		$	124		$	2.71		$	2.60		$	0.11

(1) 2015 amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Energy segment.

DVP

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

	Third Quarter							Year-To-Date
	2016		2015		% Change			2016		2015		% Change
Electricity delivered (million MWh)		24.1		22.6		7	%		64.2		65.6		(2	)%
Degree days (electric distribution service area):
Cooling		1,326		1,174		13			1,755		1,819		(4	)
Heating		—		—		—			2,247		2,578		(13	)
Average electric distribution customer accounts (thousands)(1)		2,552		2,526		1			2,546		2,522		1

(1) Period average.

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

	Third Quarter 2016 vs. 2015 Increase (Decrease)						Year-To-Date 2016 vs. 2015 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	12		$	0.02		$	(14	)	$	(0.02	)
Other		5			0.01			—			—
FERC transmission equity return		9			0.01			30			0.05
Storm damage and service restoration		(5	)		(0.01	)		(17	)		(0.03	)
Depreciation and amortization		(2	)		—			(7	)		(0.01	)
Other		(5	)		(0.01	)		(11	)		(0.02	)
Share dilution		—			(0.01	)		—			(0.02	)
Change in net income contribution	$	14		$	0.01		$	(19	)	$	(0.05	)

Dominion Generation

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

	Third Quarter							Year-To-Date
	2016		2015		% Change			2016		2015		% Change
Electricity supplied (million MWh):
Utility		24.8		22.9		8	%		67.1		66.2		1	%
Merchant		7.9		7.6		4			21.2		20.6		3
Degree days (electric utility service area):
Cooling		1,326		1,174		13			1,755		1,819		(4	)
Heating		—		—		—			2,247		2,578		(13	)

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

	Third Quarter 2016 vs. 2015 Increase (Decrease)						Year-To-Date 2016 vs. 2015 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	32		$	0.05		$	(22	)	$	(0.04	)
Other		10			0.02			12			0.02
Renewable energy investment tax credits(1)		212			0.35			182			0.31
Electric capacity		49			0.08			89			0.16
Outage costs		1			—			(22	)		(0.04	)
Merchant generation margin		(14	)		(0.02	)		(42	)		(0.07	)
Rate adjustment clause equity return		2			—			18			0.03
Depreciation and amortization		(5	)		(0.01	)		(15	)		(0.03	)
Other		(27	)		(0.04	)		(36	)		(0.06	)
Share dilution		—			(0.05	)		—			(0.06	)
Change in net income contribution	$	260		$	0.38		$	164		$	0.22

(1) Tax credit is reflected in Generation segment once project is placed into service.

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Dominion Energy

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

	Third Quarter							Year-To-Date
	2016		2015		% Change			2016		2015		% Change
Gas distribution throughput (bcf)(1):
Sales		2		2		—	%		18		21		(14	)%
Transportation		106		89		19			364		341		7
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		472		234		102			329		237		39
Transportation		1,069		1,050		2			1,072		1,060		1
Average retail energy marketing customer accounts (thousands)(2)		1,377		1,319		4			1,368		1,285		6

(1) Includes Dominion Questar effective September 2016.

(2) Period average.

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

	Third Quarter 2016 vs. 2015 Increase (Decrease)						Year-To-Date 2016 vs. 2015 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Gas distribution margin:
Weather	$	—		$	—		$	(7	)	$	(0.01	)
Other		5			0.01			11			0.02
Assignment of shale development rights		(27	)		(0.06	)		(47	)		(0.09	)
Dominion Questar Combination		5			0.01			5			0.01
Other		(1	)		—			12			0.02
Share dilution		—			(0.01	)		—			(0.03	)
Change in net income contribution	$	(18	)	$	(0.05	)	$	(26	)	$	(0.08	)

Corporate and Other

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

	Third Quarter									Year-To-Date
	2016			2015			$ Change			2016			2015			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	4		$	(18	)	$	22		$	(22	)	$	(80	)	$	58
Specific items attributable to corporate operations		(30	)		—			(30	)		(41	)		(2	)		(39	)
Total specific items		(26	)		(18	)		(8	)		(63	)		(82	)		19
Other corporate operations:
Renewable energy investment tax credits		(143	)		5			(148	)		(11	)		15			(26	)
Other		(65	)		(62	)		(3	)		(172	)		(184	)		12
Total other corporate operations		(208	)		(57	)		(151	)		(183	)		(169	)		(14	)
Total net expense	$	(234	)	$	(75	)	$	(159	)	$	(246	)	$	(251	)	$	5
EPS impact	$	(0.37	)	$	(0.13	)	$	(0.24	)	$	(0.40	)	$	(0.42	)	$	0.02

Total Specific Items

Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing those segments’ performance or in allocating resources. 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.

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Virginia Power

Results of Operations

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

	Third Quarter						Year-To-Date
	2016		2015		$ Change		2016		2015		$ Change
(millions)
Net income	$	503	$	385	$	118	$	1,046	$	900	$	146

Overview

Third Quarter 2016 vs. 2015

Net income increased 31%, primarily due to an increase in sales to retail customers from an increase in cooling degree days and the new PJM capacity performance market effective June 2016.

Year-To-Date 2016 vs. 2015

Net income increased 16%, primarily due to an increase in rate adjustment clause revenue, the new PJM capacity performance market effective June 2016 and the absence of a write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015.

Analysis of Consolidated Operations

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

	Third Quarter								Year-To-Date
	2016			2015		$ Change			2016		2015		$ Change
(millions)
Operating revenue	$	2,211		$	2,058	$	153		$	5,877	$	6,008	$	(131	)
Electric fuel and other energy-related purchases		516			554		(38	)		1,527		1,861		(334	)
Purchased (excess) electric capacity		(6	)		75		(81	)		107		259		(152	)
Net revenue		1,701			1,429		272			4,243		3,888		355
Other operations and maintenance		443			375		68			1,279		1,216		63
Depreciation and amortization		270			244		26			765		713		52
Other taxes		74			69		5			218		212		6
Other income		13			13		—			47		49		(2	)
Interest and related charges		118			116		2			345		332		13
Income tax expense		306			253		53			637		564		73

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

Third Quarter 2016 vs. 2015

Net revenue increased 19%, primarily reflecting:

• An $81 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($70 million) and the expiration of non-utility generator contracts in 2015 ($16 million);

• An increase from rate adjustment clauses ($78 million); and

• An increase in sales to retail customers from an increase in cooling degree days ($74 million).

Other operations and maintenance increased 18%, primarily reflecting:

• A $27 million increase in salaries, wages and benefits and general administrative expenses;

• An $11 million increase due to union workforce contract renegotiations;

• A $9 million increase in storm damage and service restoration costs; and

• A $9 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income.

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

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

Year-To-Date 2016 vs. 2015

Net revenue increased 9%, primarily reflecting:

• A $147 million electric capacity benefit, primarily due to the new PJM capacity performance market effective June 2016 ($92 million) and the expiration of non-utility generator contracts in 2015 ($56 million);

• An increase from rate adjustment clauses ($129 million); and

• The absence of an $85 million write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015; partially offset by

• A decrease in sales to retail customers from a reduction in cooling and heating degree days ($58 million).

Other operations and maintenance increased 5%, primarily reflecting:

• A $38 million increase in salaries, wages and benefits and general administrative expenses;

• Organizational design initiative costs ($32 million);

• A $28 million increase in storm damage and service restoration costs; and

• An $11 million increase due to union workforce contract renegotiations; partially offset by

• The absence of a $45 million charge related to ash pond and landfill closure costs at certain utility generation facilities.

Income tax expense increased 13%, primarily due to higher pre-tax income.

Dominion Gas

Results of Operations

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

	Third Quarter							Year-To-Date
	2016		2015		$ Change			2016		2015		$ Change
(millions)
Net income	$	83	$	111	$	(28	)	$	286	$	357	$	(71	)

Overview

Third Quarter 2016 vs. 2015

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

Year-To-Date 2016 vs. 2015

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

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Analysis of Consolidated Operations

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

	Third Quarter							Year-To-Date
	2016		2015		$ Change			2016		2015		$ Change
(millions)
Operating revenue	$	382	$	365	$	17		$	1,181	$	1,291	$	(110	)
Purchased gas		21		8		13			71		103		(32	)
Other energy-related purchases		4		4		—			8		17		(9	)
Net revenue		357		353		4			1,102		1,171		(69	)
Other operations and maintenance		133		63		70			331		261		70
Depreciation and amortization		55		53		2			150		157		(7	)
Other taxes		36		35		1			127		127		—
Other income		7		4		3			22		17		5
Interest and related charges		23		18		5			68		53		15
Income tax expense		34		77		(43	)		162		233		(71	)

An analysis of Dominion Gas’ results of operations follows:

Third Quarter 2016 vs. 2015

Net revenue increased 1%, primarily reflecting:

• A $7 million increase from regulated natural gas distribution operations, primarily due to an increase in AMR and PIR program revenues; partially offset by

• A $2 million decrease from regulated natural gas transmission operations, primarily reflecting:

• An $8 million decrease in NGL activities, due to decreased volumes ($5 million) and prices ($3 million); partially offset by

• A $2 million increase in services performed for Atlantic Coast Pipeline; and

• A $2 million increase in gas transportation and storage activities, primarily due to increased regulated gas sales ($19 million), partially offset by decreased demand charges ($8 million) and increased fuel costs ($8 million).

Other operations and maintenance increased $70 million, primarily reflecting:

• A $47 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields;

• An $8 million increase due to union workforce temporary work stoppage;

• A $4 million increase in salaries, wages and benefits and general administrative expenses; and

• A $2 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income.

Interest and related charges increased 28%, primarily due to higher interest expense resulting from the issuances of senior notes in November 2015 and the second quarter of 2016.

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

Year-To-Date 2016 vs. 2015

Net revenue decreased 6%, primarily reflecting:

• A $38 million decrease from regulated natural gas transmission operations, primarily reflecting:

• A $39 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($29 million) and decreased fuel retained ($10 million); and

• A $17 million decrease in NGL activities, due to decreased volumes ($12 million) and prices ($5 million); partially offset by

• A $17 million increase in services performed for Atlantic Coast Pipeline; and

• A $31 million decrease from regulated natural gas distribution operations, primarily reflecting:

• A decrease in rate adjustment clause revenue related to low income assistance programs ($33 million); and

• A decrease in sales to customers due to a reduction in heating degree days ($6 million); partially offset by

• An increase in AMR and PIR program revenues ($12 million).

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Other operations and maintenance expense increased 27%, primarily reflecting:

• A $78 million decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields;

• A $17 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;

• Organizational design initiative costs ($10 million); and

• An $8 million increase due to union workforce temporary work stoppage; partially offset by

• A $33 million decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income.

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

Interest and related charges increased 28%, primarily due to higher interest expense resulting from the issuances of senior notes in November 2015 and the second quarter of 2016.

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

Liquidity and Capital Resources

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

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, which expired in September 2016. During the nine months ended September 30, 2016, Dominion purchased approximately 658,000 common units for $17 million.

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

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

	2016			2015
(millions)
Cash and cash equivalents at January 1	$	607		$	318
Cash flows provided by (used in):
Operating activities		3,386			3,453
Investing activities		(9,029	)		(4,350	)
Financing activities		5,287			817
Net decrease in cash and cash equivalents		(356	)		(80	)
Cash and cash equivalents at September 30	$	251		$	238

Operating Cash Flows

Net cash provided by Dominion’s operating activities decreased $67 million, primarily due to changes in net margin collateral requirements and 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, 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.

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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.

Credit Risk

Dominion’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion’s credit exposure as of 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
(millions)
Investment grade(1)	$	55	$	15	$	40
Non-investment grade(2)		4		—		4
No external ratings:
Internally rated - investment grade(3)		7		—		7
Internally rated - non-investment grade(4)		30		—		30
Total	$	96	$	15	$	81

(1) Designations as investment grade are based upon minimum credit ratings assigned by Moody’s Investors Service and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 49% of the total net credit exposure.

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

(3) The five largest counterparty exposures, combined, for this category represented approximately 9% of the total net credit exposure.

(4) The five largest counterparty exposures, combined, for this category represented approximately 16% of the total net credit exposure.

Investing Cash Flows

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

Financing Cash Flows and Liquidity

Dominion relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed further in Credit Ratings and Debt Covenants in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 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 $4.5 billion, primarily reflecting higher net debt issuances and higher common stock issuances in connection with the Dominion Questar Combination.

See 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

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

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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 September 30, 2016, there have been no additional changes in Dominion’s credit ratings.

Debt Covenants

In the Debt Covenants section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015, there is a discussion on the various covenants present in the enabling agreements underlying Dominion’s debt. As of 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 has, with respect to Dominion only, been temporarily increased to 70% until the end of the fiscal quarter ending June 30, 2017.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

Other than debt and financing obligations associated with the Dominion Questar Combination discussed in Note 3 to the Consolidated Financial Statements, as of 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.

Use of Off-Balance Sheet Arrangements

As of 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.

Leasing Arrangement

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 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.

Future Issues and Other Matters

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by, and subsequent to, the dates of Dominion’s Consolidated Financial Statements that may impact future results of operations, financial condition and/or cash flows. This section should be read in conjunction with Item 1. Business and Future Issues and Other Matters in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015 and Future Issues and Other Matters in MD&A in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016 and June 30, 2016.

Environmental Matters

Dominion is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. See

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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.

Legal Matters

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 and Item 1. Legal Proceedings 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 legal matters.

Collective Bargaining Agreement

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.

Regulatory Matters

See Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015, and Note 12 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 regulatory matters.

Electric Transmission Project

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.

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ITEM 3.

QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

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

Market Risk Sensitive Instruments and Risk Management

The Companies’ financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in Dominion’s and Virginia Power’s electric operations and Dominion’s and Dominion Gas’ natural gas procurement and marketing operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt and future issuances of debt. In addition, the Companies are exposed to investment price risk through various portfolios of equity and debt securities.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in commodity prices or interest rates.

Commodity Price Risk

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% decrease in commodity prices would have resulted in a decrease in fair value of $34 million and $24 million of Dominion’s commodity-based derivative instruments as of 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 $51 million and $42 million of Virginia Power’s commodity-based derivative instruments as of 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 $4 million and $5 million of Dominion Gas’ commodity-based derivative instruments as of 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.

Interest Rate Risk

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

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As of September 30, 2016, Dominion and Virginia Power had $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 $2 million and $46 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at 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 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 have resulted in a $4 million decrease in the fair value of Dominion Gas’ foreign currency swaps at 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.

Investment Price Risk

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

Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $113 million and $134 million for the nine months ended 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 $146 million for the nine months ended September 30, 2016, and a net decrease in unrealized gains on these investments of $260 million and $157 million for the nine months ended September 30, 2015 and for the year ended December 31, 2015, respectively.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $51 million and $67 million for the nine months ended 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 $77 million for the nine months ended September 30, 2016, and a net decrease in unrealized gains on these investments of $123 million and $76 million for the nine months ended September 30, 2015 and for the year ended December 31, 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.

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ITEM 4. CONTROLS AND PROCEDURES

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

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

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.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, the Companies are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Companies, or permits issued by various local, state and/or federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Companies and their subsidiaries are involved in various legal proceedings.

In 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:

• Notes 13 and 22 to the Consolidated Financial Statements and Future Issues and Other Matters in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015.

• Notes 12 and 15 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2016.

• Notes 12 and 15 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended June 30, 2016.

• Notes 12 and 15 in this report.

ITEM 1A. RISK FACTORS

The Companies businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond the Companies’ control. A number of these risk factors have been identified in the Companies’ Annual Report on Form 10-K for the year ended December 31, 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, see Forward-Looking Statements in MD&A in this report.

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

Dominion

ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares (or Units) Purchased(1)		Average Price Paid per Share (or Unit)(2)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(3)
7/1/16-7/31/16		5,751	$	77.86		—	19,629,059 shares/ $1.18 billion
8/1/16-8/31/16		848		77.58		—	19,629,059 shares/ $1.18 billion
9/1/16-9/30/16		178		74.06		—	19,629,059 shares/ $1.18 billion
Total		6,777	$	77.73		—	19,629,059 shares/ $1.18 billion

(1) In July, August and September 2016, 5,751 shares, 848 shares and 178 shares, respectively, were tendered by employees to satisfy tax withholding obligations on vested restricted stock.

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

(3) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion Board of Directors was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion.

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ITEM 6. EXHIBITS

Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas
3.1.a	Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).	X
3.1.b	Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255).		X
3.1.c	Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).			X
3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective December 17, 2015 (Exhibit 3.1, Form 8-K filed December 17, 2015, File No. 1-8489).	X
3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).		X
3.2.c	Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066).			X
4	Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.	X	X	X
4.1	Indenture, dated as of June 1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489); First Supplemental Indenture, dated as of June 1, 2015 (Exhibit 4.2, Form 8-K filed June 15, 2015, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2015 (Exhibit 4.2, Form 8-K filed September 24, 2015, File No. 1-8489); Third Supplemental Indenture, dated as of February 1, 2016 (Exhibit 4.7, Form 10-K for the fiscal year ended December 31, 2015 filed February 26, 2016, File No. 1-8489); Fourth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.2, Form 8-K filed August 9, 2016, File No. 1-8489); Fifth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.3, Form 8-K filed August 9, 2016, File No. 1-8489); Sixth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.4, Form 8-K filed August 9, 2016, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2016 (filed herewith).	X
4.2	Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2013, File No. 1-8489); Eighth Supplemental Indenture, dated March 7, 2016 (Exhibit 4.4, Form 8-K filed March 7, 2016, File No. 1-8489); Ninth Supplemental Indenture, dated May 26, 2016 (Exhibit 4.4, Form 8-K filed May 26, 2016, File No. 1-8489); Tenth Supplemental Indenture, dated as of July 1, 2016 (Exhibit 4.3, Form 8-K filed July 19, 2016, File No. 1-8489); Eleventh Supplemental Indenture, dated August 1, 2016 (Exhibit 4.3, Form 8-K filed August 15, 2016, File No. 1-8489); Twelfth Supplemental Indenture, dated August 1, 2016 (Exhibit 4.4, Form 8-K filed August 15, 2016, File No. 1-8489).	X
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

103

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 September 30, 2016, filed on 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 September 30, 2016, filed on 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

104

SIGNATURE

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

	DOMINION RESOURCES, INC. Registrant
November 9, 2016	/s/ Michele L. Cardiff
	Michele L. Cardiff Vice President, Controller and Chief Accounting Officer
	VIRGINIA ELECTRIC AND POWER COMPANY Registrant
November 9, 2016	/s/ Michele L. Cardiff
	Michele L. Cardiff Vice President, Controller and Chief Accounting Officer
	DOMINION GAS HOLDINGS, LLC Registrant
November 9, 2016	/s/ Michele L. Cardiff
	Michele L. Cardiff Vice President, Controller and Chief Accounting Officer

105

EXHIBIT INDEX

Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas
3.1.a	Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).	X
3.1.b	Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255).		X
3.1.c	Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).			X
3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective December 17, 2015 (Exhibit 3.1, Form 8-K filed December 17, 2015, File No. 1-8489).	X
3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).		X
3.2.c	Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066).			X
4	Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.	X	X	X
4.1	Indenture, dated as of June 1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489); First Supplemental Indenture, dated as of June 1, 2015 (Exhibit 4.2, Form 8-K filed June 15, 2015, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2015 (Exhibit 4.2, Form 8-K filed September 24, 2015, File No. 1-8489); Third Supplemental Indenture, dated as of February 1, 2016 (Exhibit 4.7, Form 10-K for the fiscal year ended December 31, 2015 filed February 26, 2016, File No. 1-8489); Fourth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.2, Form 8-K filed August 9, 2016, File No. 1-8489); Fifth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.3, Form 8-K filed August 9, 2016, File No. 1-8489); Sixth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.4, Form 8-K filed August 9, 2016, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2016 (filed herewith).	X
4.2	Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2013, File No. 1-8489); Eighth Supplemental Indenture, dated March 7, 2016 (Exhibit 4.4, Form 8-K filed March 7, 2016, File No. 1-8489); Ninth Supplemental Indenture, dated May 26, 2016 (Exhibit 4.4, Form 8-K filed May 26, 2016, File No. 1-8489); Tenth Supplemental Indenture, dated as of July 1, 2016 (Exhibit 4.3, Form 8-K filed July 19, 2016, File No. 1-8489); Eleventh Supplemental Indenture, dated August 1, 2016 (Exhibit 4.3, Form 8-K filed August 15, 2016, File No. 1-8489); Twelfth Supplemental Indenture, dated August 1, 2016 (Exhibit 4.4, Form 8-K filed August 15, 2016, File No. 1-8489).	X

106

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
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 September 30, 2016, filed on 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 September 30, 2016, filed on 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

107

EX-4.1

Exhibit 4.1

DOMINION RESOURCES, INC.

Issuer

AND

DEUTSCHE BANK TRUST COMPANY AMERICAS

Trustee

Seventh Supplemental Indenture

Dated as of September 1, 2016

$300,000,000

2016 Series E 1.50% Senior Notes

due 2018

TABLE OF CONTENTS^*

ARTICLE I 2016 SERIES E 1.50% SENIOR NOTES DUE 2018		1
SECTION 101.	Establishment	1
SECTION 102.	Definitions	2
SECTION 103.	Payment of Principal and Interest	5
SECTION 104.	Denominations	5
SECTION 105.	Global Securities	6
SECTION 106.	Redemption	6
SECTION 107.	Sinking Fund	7
SECTION 108.	Additional Interest on Overdue Amounts	7
SECTION 109.	Paying Agent	7
ARTICLE II TRANSFER AND EXCHANGE		7
SECTION 201.	Transfer and Exchange of Global Securities	7
SECTION 202.	Restricted Legend	8
SECTION 203.	Removal of Restricted Legend	9
SECTION 204.	Registration of Transfer or Exchange	9
SECTION 205.	Preservation of Information	9
SECTION 206.	Acknowledgment of Restrictions; Indemnification; No Obligation of Trustee	10
ARTICLE III MISCELLANEOUS PROVISIONS		10
SECTION 301.	Ratification and Incorporation of Base Indenture	10
SECTION 302.	Executed in Counterparts	11
SECTION 303.	Assignment	11
SECTION 304.	Trustee’s Disclaimer	11

^*  This Table of Contents does not constitute part of the Indenture or have any bearing upon the interpretation of any of its terms and provisions.

THIS SEVENTH SUPPLEMENTAL INDENTURE is made as of the 1st day of September, 2016, by and between DOMINION RESOURCES, INC., a Virginia corporation, having its principal office at 120 Tredegar Street, Richmond, Virginia 23219 (the “Company”), and DEUTSCHE BANK TRUST COMPANY AMERICAS, a New York banking corporation, as Trustee, having a corporate trust office at 60 Wall Street, 16^th Floor, New York, New York 10005 (herein called the “Trustee”).

W I T N E S S E T H:

WHEREAS, the Company has heretofore entered into an Indenture dated as of June 1, 2015, between the Company and the Trustee (as amended, restated or otherwise modified, the “Base Indenture”) with respect to senior debt securities;

WHEREAS, the Base Indenture is incorporated herein by this reference and the Base Indenture, as heretofore supplemented, as further supplemented by this Seventh Supplemental Indenture, and as may be hereafter supplemented or amended from time to time, is herein called the “Indenture”;

WHEREAS, under the Base Indenture, a new series of Securities may at any time be established in accordance with the provisions of the Base Indenture and the terms of such series may be described by a supplemental indenture executed by the Company and the Trustee;

WHEREAS, the Company proposes to create under the Indenture a new series of Securities;

WHEREAS, additional Securities of other series hereafter established, except as may be limited in the Base Indenture as at the time supplemented and modified, may be issued from time to time pursuant to the Indenture as at the time supplemented and modified; and

WHEREAS, all conditions necessary to authorize the execution and delivery of this Seventh Supplemental Indenture and to make it a valid and binding obligation of the Company have been done or performed.

NOW, THEREFORE, in consideration of the agreements and obligations set forth herein and for other good and valuable consideration, the sufficiency of which is hereby acknowledged, the parties hereto hereby agree as follows:

ARTICLE I

2016 SERIES E 1.50% SENIOR NOTES DUE 2018

SECTION 101. Establishment. There is hereby established a new series of Securities to be issued under the Indenture, to be designated as the Company’s 2016 Series E 1.50% Senior Notes due 2018 (the “Series E Senior Notes”).

There are to be authenticated and delivered $300,000,000 principal amount of Series E Senior Notes, and such principal amount of the Series E Senior Notes may be increased from time to time pursuant to the penultimate paragraph of Section 301 of the Base Indenture. All Series E Senior Notes need not be issued at the same time and such series may be reopened at

any time, without the consent of any Holder, for issuances of additional Series E Senior Notes. Any such additional Series E Senior Notes will have the same interest rate, maturity and other terms as those initially issued, and shall be consolidated with and part of the same series of Series E Senior Notes initially issued under this Seventh Supplemental Indenture. Further Series E Senior Notes may also be authenticated and delivered as provided by Sections 304, 305, 306, 905 or 1107 of the Base Indenture.

The Series E Senior Notes shall be issued as Registered Securities in global form without coupons, in substantially the form set out in Exhibit A hereto. The entire initially issued principal amount of the Series E Senior Notes shall initially be evidenced by one or more certificates issued to Cede & Co., as nominee for The Depository Trust Company.

The form of the Trustee’s Certificate of Authentication for the Series E Senior Notes shall be in substantially the form set forth in Exhibit B hereto.

Each Series E Senior Note shall be dated the date of authentication thereof and shall bear interest from the date of original issuance thereof or from the most recent Interest Payment Date to which interest has been paid or duly provided for.

SECTION 102. Definitions. The following defined terms used herein shall, unless the context otherwise requires, have the meanings specified below. Capitalized terms used herein for which no definition is provided herein shall have the meanings set forth in the Base Indenture. Unless the context otherwise requires, any reference to a “Section” refers to a Section of this Seventh Supplemental Indenture.

“Adjusted Treasury Rate” means, with respect to any Redemption Date, the rate per annum equal to the semiannual equivalent yield to maturity or interpolated (on a day count basis) of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such Redemption Date.

“Business Day” means a day other than (i) a Saturday or a Sunday, (ii) a day on which banks in New York, New York are authorized or obligated by law or executive order to remain closed or (iii) a day on which the Corporate Trust Office is closed for business.

“Comparable Treasury Issue” means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of the Series E Senior Notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term in years and months of the Series E Senior Notes.

“Comparable Treasury Price” for any Redemption Date means (i) the average of the Reference Treasury Dealer Quotations for such Redemption Date, after excluding the highest and lowest Reference Treasury Dealer Quotations, or (ii) if the Independent Investment Banker obtains fewer than five such Reference Treasury Dealer Quotations, the average of all such quotations.

“Distribution Compliance Period” has the meaning set forth in Section 204.

2

“Independent Investment Banker” means RBC Capital Markets, LLC and its successors or affiliates, as selected by the Company, or if such firm is unwilling or unable to serve as such, an independent investment and banking institution of national standing appointed by the Company.

“Interest Payment Dates” means March 30 and September 30 of each year, commencing on March 30, 2017.

“Original Issue Date” means September 28, 2016.

“Outstanding,” when used with respect to the Series E Senior Notes, means, as of the date of determination, all Series E Senior Notes theretofore authenticated and delivered under the Indenture, except:

(i) Series E Senior Notes theretofore canceled by the Trustee or delivered to the Trustee for cancellation;

(ii) Series E Senior Notes for whose payment at the Maturity thereof money in the necessary amount has been theretofore deposited (other than pursuant to Section 402 of the Base Indenture) with the Trustee or any Paying Agent (other than the Company) in trust or set aside and segregated in trust by the Company (if the Company shall act as its own Paying Agent) for the Holders of such Series E Senior Notes, provided that, if such Series E Senior Notes are to be redeemed, notice of such redemption has been duly given pursuant to this Indenture or provision therefor satisfactory to the Trustee has been made;

(iii) Series E Senior Notes with respect to which the Company has effected defeasance or covenant defeasance pursuant to Section 402 of the Base Indenture, except to the extent provided in Section 402 of the Base Indenture; and

(iv) Series E Senior Notes that have been paid pursuant to Section 306 of the Base Indenture or in exchange for or in lieu of which other Series E Senior Notes have been authenticated and delivered pursuant to the Indenture, other than any such Series E Senior Notes in respect of which there shall have been presented to the Trustee proof satisfactory to it that such Series E Senior Notes are held by a bona fide purchaser in whose hands such Series E Senior Notes are valid obligations of the Company; provided, however, that in determining whether the Holders of the requisite principal amount of Outstanding Series E Senior Notes have given any request, demand, authorization, direction, notice, consent or waiver under the Indenture or are present at a meeting of Holders of Series E Senior Notes for quorum purposes, Series E Senior Notes owned by the Company or any other obligor upon the Series E Senior Notes or any Affiliate of the Company or such other obligor shall be disregarded and deemed not to be Outstanding, except that, in determining whether the Trustee shall be protected in making any such determination or relying upon any such request, demand, authorization, direction, notice, consent or waiver, only Series E Senior Notes which a Responsible Officer of the Trustee actually knows to be so owned shall be so disregarded. Series E Senior Notes so owned which shall have been pledged in good faith may be regarded as Outstanding if the pledgee establishes to the satisfaction of the Trustee (A) the pledgee’s right so to act with respect to such Series E Senior Notes and (B) that the pledgee is not the Company or any other obligor upon the Series E Senior Notes or an Affiliate of the Company or such other obligor.

3

“Primary Treasury Dealer” means a primary United States government securities dealer in the United States as designated by the Federal Reserve Bank of New York.

“QIB” means a “qualified institutional buyer” as defined in Rule 144A.

“Reference Treasury Dealer” means (i) RBC Capital Markets, LLC and its successors or affiliates; provided that, if such firm or its successors ceases to be a Primary Treasury Dealer, the Company shall substitute another Primary Treasury Dealer; and (ii) up to four other Primary Treasury Dealers selected by the Company.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any Redemption Date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue related to the Series E Senior Notes being redeemed (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker at 3:30 p.m., New York City time, on the third Business Day preceding such Redemption Date.

“Regular Record Date” means, with respect to each Interest Payment Date, the close of business on the Business Day preceding such Interest Payment Date; provided that, with respect to Series E Senior Notes that are not represented by one or more Global Securities, the Regular Record Date shall be the close of business on the 15th calendar day (whether or not a Business Day) preceding such Interest Payment Date.

“Regulation S” means Regulation S promulgated under the Securities Act.

“Regulation S Global Security” has the meaning set forth in Section 105.

“Restricted Legend” has the meaning set forth in Section 202.

“Restricted Security” has the meaning set forth in Section 202.

“Rule 144A” means Rule 144A promulgated under the Securities Act.

“Rule 144A Global Security” has the meaning set forth in Section 105.

“Securities Act” means the Securities Act of 1933, as amended.

“Series E Senior Notes” has the meaning set forth in Section 101.

“Stated Maturity” means February 15, 2018.

The terms “Company,” “Trustee,” “Base Indenture,” and “Indenture” shall have the respective meanings set forth in the recitals to this Seventh Supplemental Indenture and the paragraph preceding such recitals.

4

SECTION 103. Payment of Principal and Interest. The principal of the Series E Senior Notes shall be due at the Stated Maturity (unless earlier redeemed). The unpaid principal amount of the Series E Senior Notes shall bear interest at the rate of 1.50% per annum until paid or duly provided for, such interest to accrue from the Original Issue Date or from the most recent Interest Payment Date to which interest has been paid or duly provided for. Interest shall be paid semi-annually in arrears on each Interest Payment Date to the Person in whose name the Series E Senior Notes are registered on the Regular Record Date for such Interest Payment Date; provided that interest payable at the Stated Maturity of principal or on a Redemption Date as provided herein will be paid to the Person to whom principal is payable. Any such interest that is not so punctually paid or duly provided for will forthwith cease to be payable to the Holders on such Regular Record Date and may either be paid to the Person or Persons in whose name the Series E Senior Notes are registered at the close of business on a Special Record Date for the payment of such defaulted interest to be fixed by the Trustee (in accordance with Section 307 of the Base Indenture), notice whereof shall be given to Holders of the Series E Senior Notes not less than ten (10) days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange, if any, on which the Series E Senior Notes may be listed, and upon such notice as may be required by any such exchange, all as more fully provided in the Base Indenture.

Payments of interest on the Series E Senior Notes will include interest accrued to but excluding the respective Interest Payment Dates. Interest payments for the Series E Senior Notes shall be computed and paid on the basis of a 360-day year of twelve 30-day months. In the event that any date on which interest is payable on the Series E Senior Notes is not a Business Day, then payment of the interest payable on such date will be made on the next succeeding day that is a Business Day (and without any interest or payment in respect of any such delay), in each case with the same force and effect as if made on the date the payment was originally payable.

Payment of the principal and interest on the Series E Senior Notes shall be made at the office of the Paying Agent in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts, with any such payment that is due at the Stated Maturity of any Series E Senior Notes, upon redemption or repurchase being made upon surrender of such Series E Senior Notes to the Paying Agent. Payments of interest (including interest on any Interest Payment Date) will be made, subject to such surrender where applicable, at the option of the Company, (i) by check mailed to the address of the Person entitled thereto as such address shall appear in the Security Register or (ii) by wire transfer at such place and to such account at a banking institution in the United States as may be designated in writing to the Trustee at least sixteen (16) days prior to the date for payment by the Person entitled thereto. In the event that any date on which principal and interest is payable on the Series E Senior Notes is not a Business Day, then payment of the principal and interest payable on such date will be made on the next succeeding day that is a Business Day (and without any interest or payment in respect of any such delay), in each case with the same force and effect as if made on the date the payment was originally payable.

SECTION 104. Denominations. The Series E Senior Notes may be issued in denominations of $2,000, or any greater integral multiple of $1,000.

5

SECTION 105. Global Securities. The Series E Senior Notes offered and sold to QIBs in reliance on Rule 144A will be initially issued in the form of one or more Global Securities (the “Rule 144A Global Security”), and the Series E Senior Notes offered and sold in offshore transactions to non-U.S. persons in reliance on Regulation S will be initially issued in the form of one or more Global Securities (the “Regulation S Global Security”), in each case registered in the name of the Depositary (which shall be The Depository Trust Company) or its nominee. Except under the limited circumstances described below, Series E Senior Notes represented by such Global Securities will not be exchangeable for, and will not otherwise be issuable as, Series E Senior Notes in definitive form registered in names other than the Depositary or its nominee. The Global Securities described above may not be transferred except by the Depositary to a nominee of the Depositary or by a nominee of the Depositary to the Depositary or another nominee of the Depositary or to a successor Depositary or its nominee.

Owners of beneficial interests in such a Global Security will not be considered the Holders thereof for any purpose under the Indenture, and no Global Security representing a Series E Senior Note shall be exchangeable, except for another Global Security of like denomination and tenor to be registered in the name of the Depositary or its nominee or to a successor Depositary or its nominee or except as described below. The rights of Holders of such Global Security shall be exercised only through the Depositary.

A Global Security shall be exchangeable for Series E Senior Notes registered in the names of persons other than the Depositary or its nominee only if (i) the Depositary notifies the Company that it is unwilling or unable to continue as a Depositary for such Global Security and no successor Depositary shall have been appointed by the Company within 90 days of receipt by the Company of such notification, or if at any time the Depositary ceases to be a clearing agency registered under the Exchange Act at a time when the Depositary is required to be so registered to act as such Depositary and no successor Depositary shall have been appointed by the Company within 90 days after it becomes aware of such cessation, (ii) the Company in its sole discretion, and subject to the procedures of the Depositary, determines that such Global Security shall be so exchangeable, in which case Series E Senior Notes in definitive form will be printed and delivered to the Depositary, or (iii) an Event of Default has occurred and is continuing with respect to the Series E Senior Notes. Any Global Security that is exchangeable pursuant to the preceding sentence shall be exchangeable for Series E Senior Notes registered in such names as the Depositary shall direct.

SECTION 106. Redemption. The Series E Senior Notes are redeemable, in whole or in part, at any time and from time to time, at the option of the Company, at a Redemption Price equal to the greater of:

(i) 100% of the principal amount of Series E Senior Notes then Outstanding to be so redeemed, or

(ii) the sum of the present values of the remaining scheduled payments of principal and interest on the Series E Senior Notes to be redeemed (not including any portion of such payments of interest accrued as of the Redemption Date) discounted to the Redemption Date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Adjusted Treasury Rate, plus 15 basis points, as calculated by an Independent Investment Banker,

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plus, in either of the above cases, accrued and unpaid interest thereon to the Redemption Date.

The Adjusted Treasury Rate shall be calculated on the third Business Day preceding the Redemption Date.

Unless the Company defaults in the payment of the Redemption Price, on and after the Redemption Date, interest will cease to accrue on the Series E Senior Notes or portions thereof called for redemption.

In the event of the redemption of the Series E Senior Notes in part only, a new Series E Senior Note or Notes for the unredeemed portion will be issued in the name or names of the Holders thereof upon surrender thereof.

The Company shall notify the Trustee in writing of the Redemption Price promptly after the calculation thereof and the Trustee shall have no responsibility for such calculation. The notice of redemption shall be sent in accordance with the terms of the Base Indenture.

SECTION 107. Sinking Fund ; Conversion. The Series E Senior Notes shall not have a sinking fund. The Series E Senior Notes are not convertible into or exchangeable for Equity Securities and/or any other securities.

SECTION 108. Additional Interest on Overdue Amounts. Any principal of and installment of interest on the Series E Senior Notes that is overdue shall bear interest at the rate of 1.50% (to the extent that the payment of such interest shall be legally enforceable), from the dates such amounts are due until they are paid or made available for payment, and such interest shall be payable on demand.

SECTION 109. Paying Agent. The Trustee shall initially serve as Paying Agent and Security Registrar with respect to the Series E Senior Notes, with the Place of Payment initially being the Corporate Trust Office. The Company may change the Paying Agent or Security Registrar without prior notice to Holders of the Series E Senior Notes, and the Company or any of its subsidiaries may act as Paying Agent or Security Registrar.

ARTICLE II

TRANSFER AND EXCHANGE

SECTION 201. Transfer and Exchange of Global Securities. The transfer and exchange of beneficial interests in the Global Securities shall be effected through the Depositary, in accordance with this Seventh Supplemental Indenture (including applicable restrictions on transfer set forth herein, if any) and the procedures of the Depositary therefor.

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SECTION 202. Restricted Legend. Except as otherwise provided in Section 203 and as indicated on Exhibit A, each Series E Senior Note (each a “Restricted Security”) shall bear the following legend (the “Restricted Legend”) on the face thereof:

THIS SERIES E SENIOR NOTE (OR ITS PREDECESSOR) WAS ORIGINALLY ISSUED IN A TRANSACTION EXEMPT FROM REGISTRATION UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”), AND THIS SERIES E SENIOR NOTE MAY NOT BE OFFERED, SOLD OR OTHERWISE TRANSFERRED IN THE ABSENCE OF SUCH REGISTRATION OR AN APPLICABLE EXEMPTION THEREFROM. EACH PURCHASER OF THIS SERIES E SENIOR NOTE IS HEREBY NOTIFIED THAT THE SELLER OF THIS SERIES E SENIOR NOTE MAY BE RELYING ON THE EXEMPTION FROM THE PROVISIONS OF SECTION 5 OF THE SECURITIES ACT PROVIDED BY RULE 144A THEREUNDER.

THE HOLDER OF THIS SERIES E SENIOR NOTE AGREES FOR THE BENEFIT OF THE COMPANY THAT (A) THIS SERIES E SENIOR NOTE MAY BE OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED, ONLY (I) IN THE UNITED STATES TO A PERSON WHOM THE SELLER REASONABLY BELIEVES IS A QUALIFIED INSTITUTIONAL BUYER (AS DEFINED IN RULE 144A UNDER THE SECURITIES ACT) IN A TRANSACTION MEETING THE REQUIREMENTS OF RULE 144A, (II) OUTSIDE THE UNITED STATES IN AN OFFSHORE TRANSACTION IN ACCORDANCE WITH RULE 904 UNDER THE SECURITIES ACT, (III) PURSUANT TO AN EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT PROVIDED BY RULE 144 THEREUNDER (IF AVAILABLE), (IV) PURSUANT TO AN EFFECTIVE REGISTRATION STATEMENT UNDER THE SECURITIES ACT, OR (V) TO AN INSTITUTIONAL “ACCREDITED INVESTOR” (AS DEFINED IN RULE 501(A)(1), (2), (3) OR (7) OF REGULATION D UNDER THE SECURITIES ACT) THAT IS ACQUIRING THE NOTE FOR ITS OWN ACCOUNT, OR FOR THE ACCOUNT OF SUCH AN INSTITUTIONAL “ACCREDITED INVESTOR” FOR INVESTMENT PURPOSES AND NOT WITH A VIEW TO, OR FOR OFFER OR SALE IN CONNECTION WITH, ANY DISTRIBUTION IN VIOLATION OF THE SECURITIES ACT, IN EACH OF CASES (I) THROUGH (V) IN ACCORDANCE WITH ANY APPLICABLE SECURITIES LAWS OF ANY STATE OF THE UNITED STATES, AND (B) THE HOLDER WILL, AND EACH SUBSEQUENT HOLDER IS REQUIRED TO, NOTIFY ANY PURCHASER OF THIS SERIES E SENIOR NOTE FROM IT OF THE RESALE RESTRICTIONS REFERRED TO IN CLAUSE (A) ABOVE.

THE HOLDER AGREES THAT IT WILL DELIVER TO EACH PERSON TO WHOM THIS SERIES E SENIOR NOTE OR AN INTEREST HEREIN IS TRANSFERRED A NOTICE SUBSTANTIALLY TO THE EFFECT OF THIS LEGEND.

THE HOLDER AGREES THAT, BEFORE THE HOLDER OFFERS, SELLS OR OTHERWISE TRANSFERS THIS SERIES E SENIOR NOTE, THE COMPANY MAY REQUIRE THE HOLDER OF THIS SERIES E SENIOR NOTE TO DELIVER A WRITTEN OPINION, CERTIFICATIONS AND/OR OTHER INFORMATION THAT IT REASONABLY REQUIRES TO CONFIRM THAT SUCH PROPOSED TRANSFER IS BEING MADE PURSUANT TO AN EXEMPTION FROM THE REGISTRATION REQUIREMENTS OF THE UNITED STATES.

AS USED IN THIS SERIES E SENIOR NOTE, THE TERMS “OFFSHORE TRANSACTION,” “U.S. PERSON” AND “UNITED STATES” HAVE THE MEANINGS GIVEN TO THEM BY RULE 902 OF REGULATION S UNDER THE SECURITIES ACT.

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SECTION 203. Removal of Restricted Legend. The Company may instruct the Trustee in writing to cancel any Series E Senior Note and, upon receipt of a Company Order, authenticate a replacement Series E Senior Note, registered in the name of the Holder thereof (or its transferee), that does not bear the Restricted Legend, and the Trustee will comply with such instruction, if the Company determines (upon the advice of counsel and such other certifications and evidence as the Company may reasonably require) that a Series E Senior Note is eligible for resale pursuant to Rule 144 under the Securities Act (or a successor provision) and that the Restricted Legend is no longer necessary or appropriate in order to ensure that subsequent transfers of such Series E Senior Note (or a beneficial interest therein) are effected in compliance with the Securities Act; provided, however, that in such circumstances, the Trustee shall require an Opinion of Counsel and an Officers’ Certificate prior to authenticating any such replacement Series E Senior Note.

SECTION 204. Registration of Transfer or Exchange. The registration of transfer or exchange of any Series E Senior Note (or a beneficial interest therein) that bears the Restricted Legend may only be made in compliance with the provisions of the Restricted Legend and as set forth below.

(i) Prior to and including the 40th day after the later of the commencement of the offering of the Series E Senior Notes and the Original Issue Date (such period through and including such 40th day, the “Distribution Compliance Period”), transfers by an owner of a beneficial interest in a Regulation S Global Security to a transferee who takes delivery of such interest through a Rule 144A Global Security of that series will be made only upon receipt by the Trustee of a written certification from the transferor of the beneficial interest to the effect that such transfer is being made to a Person whom the transferor reasonably believes is purchasing for its own account or accounts as to which it exercises sole investment discretion and is a QIB in a transaction meeting the requirements of Rule 144A and the requirements of applicable securities laws of any state of the United States or any other jurisdiction.

(ii) Transfers by an owner of a beneficial interest in the Rule 144A Global Security to a transferee who takes delivery through the Regulation S Global Security of that series, whether before or after the expiration of the Distribution Compliance Period, will be made only upon receipt by the Trustee of a certification from the transferor to the effect that such transfer is being made in accordance with Rule 904 of Regulation S or Rule 144 under the Securities Act and that, if such transfer is being made prior to the expiration of the Distribution Compliance Period, the interest transferred will be held immediately thereafter through Euroclear Bank S.A./NV, as operator of the Euroclear System or Clearstream Banking, société anonyme, Luxembourg.

(iii) Any beneficial interest in one of the Global Securities that is transferred to a Person who takes delivery in the form of an interest in another Global Security of that series will, upon transfer, cease to be an interest in the initial Global Security of that series and will become an interest in the other Global Security of that series and, accordingly, will thereafter be subject to all transfer restrictions, if any, and other procedures applicable to beneficial interests in such other Global Security of that series for as long as it remains such an interest.

SECTION 205. Preservation of Information. The Trustee will retain copies of all certificates, opinions and other documents received in connection with the registration of transfer

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or exchange of a Series E Senior Note (or a beneficial interest therein) in accordance with its customary policy, and the Company will have the right to request copies thereof at any reasonable time upon written notice to the Trustee.

SECTION 206. Acknowledgment of Restrictions; Indemnification; No Obligation of Trustee. By its acceptance of any Series E Senior Note bearing the Restricted Legend, each Holder of such a Series E Senior Note acknowledges the restrictions on registrations of transfer or exchange of such Series E Senior Note set forth in this Seventh Supplemental Indenture and in the Restricted Legend and agrees that it will register the transfer or exchange of such Series E Senior Note only as provided in this Seventh Supplemental Indenture. The Security Registrar shall not register a transfer or exchange of any Series E Senior Note unless such transfer or exchange complies with the restrictions on transfer or exchange of such Series E Senior Note set forth in this Seventh Supplemental Indenture. In connection with any registration of transfer or exchange of Series E Senior Notes, each Holder agrees by its acceptance of the Series E Senior Notes to furnish the Security Registrar or the Company such certifications, legal opinions or other information as either of them may reasonably require to confirm that such registration of transfer or exchange is being made pursuant to an exemption from, or a transaction not subject to, the registration requirements of the Securities Act; provided that the Security Registrar shall not be required to determine (but may rely on a determination made by the Company with respect to) the sufficiency of any such certifications, legal opinions or other information.

The Security Registrar shall retain copies of all letters, notices and other written communications received pursuant to the Indenture in accordance with its customary policy. The Company shall have the right to request copies of all such letters, notices or other written communications at any reasonable time upon the giving of written notice to the Security Registrar.

Each Holder of a Series E Senior Note agrees to indemnify the Company, the Security Registrar and the Trustee against any liability that may result from the transfer, exchange or assignment of such Holder’s Series E Senior Note in violation of any provision of this Seventh Supplemental Indenture and/or applicable United States Federal or state securities law.

The Trustee shall have no obligation or duty to monitor, determine or inquire as to compliance with any restrictions on transfer or exchange imposed under this Seventh Supplemental Indenture or under applicable law with respect to any registrations of transfer or exchange of any interest in any Series E Senior Note (including any transfers between or among members of, or participants in, the Depositary or beneficial owners of interests in any Global Security) other than to require delivery of such certificates and other documentation or evidence as are expressly required by, and to do so if and when expressly required by the terms of, this Seventh Supplemental Indenture, and to examine the same to determine substantial compliance as to form with the express requirements hereof.

ARTICLE III

MISCELLANEOUS PROVISIONS

SECTION 301. Ratification and Incorporation of Base Indenture. As supplemented hereby, the Base Indenture is in all respects ratified and confirmed by the Company. The Base Indenture and this Seventh Supplemental Indenture shall be read, taken and construed as one and the same instrument.

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SECTION 302. Executed in Counterparts. This Seventh Supplemental Indenture may be executed in several counterparts, each of which shall be deemed to be an original, and such counterparts shall together constitute but one and the same instrument. The exchange of copies of this Seventh Supplemental Indenture and of signature pages by facsimile or PDF transmission shall constitute effective execution and delivery of this Seventh Supplemental Indenture as to the parties hereto and may be used in lieu of the original, manually executed Seventh Supplemental Indenture for all purposes. Signatures of the parties hereto transmitted by facsimile or PDF shall be deemed to be their original signatures for all purposes.

SECTION 303. Assignment. The Company shall have the right at all times to assign any of its rights or obligations under the Indenture with respect to the Series E Senior Notes to a direct or indirect wholly-owned subsidiary of the Company; provided that, in the event of any such assignment, the Company shall remain primarily liable for the performance of all such obligations. The Indenture may also be assigned by the Company in connection with a transaction described in Article VIII of the Base Indenture.

SECTION 304. Trustee’s Disclaimer. All of the provisions contained in the Base Indenture in respect of the rights, powers, privileges, protections, duties and immunities of the Trustee, including without limitation its right to be indemnified, shall be applicable in respect of the Series E Senior Notes and of this Seventh Supplemental Indenture as fully and with like effect as if set forth herein in full. The Trustee accepts the amendments of the Indenture effected by this Seventh Supplemental Indenture, but on the terms and conditions set forth in the Indenture, including the terms and provisions defining and limiting the liabilities and responsibilities of the Trustee. Without limiting the generality of the foregoing, the Trustee shall not be responsible in any manner whatsoever for or with respect to any of the recitals or statements contained herein, all of which recitals or statements are made solely by the Company, or for or with respect to (i) the validity or sufficiency of this Seventh Supplemental Indenture or any of the terms or provision hereof, (ii) the proper authorization hereof by the Company by action or otherwise, (iii) the due execution hereof by the Company, or (iv) the consequences of any amendment herein provided for, and the Trustee makes no representation with respect to any such matters.

[Signature Page Follows]

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IN WITNESS WHEREOF, each party hereto has caused this instrument to be signed in its name and behalf by its duly authorized officer, all as of the day and year first above written.

DOMINION RESOURCES, INC.
By:	/s/ James R. Chapman
Name:	James R. Chapman
Title:	Senior Vice President – Mergers &
	Acquisitions and Treasurer
DEUTSCHE BANK TRUST COMPANY AMERICAS, as Trustee
By:	/s/ Carol Ng
Name:	Carol Ng
Title:	Vice President
By:	/s/ Li Jiang
Name:	Li Jiang
Title:	Vice President

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EXHIBIT A

FORM OF

2016 SERIES E 1.50% SENIOR NOTE

DUE 2018

[UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (55 WATER STREET, NEW YORK, NEW YORK) TO THE ISSUER OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND ANY CERTIFICATE ISSUED IS REGISTERED IN THE NAME OF [CEDE & CO.] OR SUCH OTHER NAME AS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY AND ANY PAYMENT IS MADE TO [CEDE & CO.], ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL SINCE THE REGISTERED OWNER HEREOF, [CEDE & CO.], HAS AN INTEREST HEREIN.]**

[THIS SERIES E SENIOR NOTE IS A GLOBAL SECURITY WITHIN THE MEANING OF THE INDENTURE HEREINAFTER REFERRED TO AND IS REGISTERED IN THE NAME OF A DEPOSITARY OR A NOMINEE THEREOF. THIS SERIES E SENIOR NOTE MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A SECURITY REGISTERED, AND NO TRANSFER OF THIS SERIES E SENIOR NOTE IN WHOLE OR IN PART MAY BE REGISTERED, IN THE NAME OF ANY PERSON OTHER THAN SUCH DEPOSITARY OR A NOMINEE THEREOF, EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE INDENTURE. EVERY SERIES E SENIOR NOTE AUTHENTICATED AND DELIVERED UPON REGISTRATION OF, TRANSFER OF, OR IN EXCHANGE FOR OR IN LIEU OF, THIS SERIES E SENIOR NOTE SHALL BE A GLOBAL SECURITY SUBJECT TO THE FOREGOING, EXCEPT IN SUCH LIMITED CIRCUMSTANCES.]**

[THIS SERIES E SENIOR NOTE (OR ITS PREDECESSOR) WAS ORIGINALLY ISSUED IN A TRANSACTION EXEMPT FROM REGISTRATION UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”), AND THIS SERIES E SENIOR NOTE MAY NOT BE OFFERED, SOLD OR OTHERWISE TRANSFERRED IN THE ABSENCE OF SUCH REGISTRATION OR AN APPLICABLE EXEMPTION THEREFROM. EACH PURCHASER OF THIS SERIES E SENIOR NOTE IS HEREBY NOTIFIED THAT THE SELLER OF THIS SERIES E SENIOR NOTE MAY BE RELYING ON THE EXEMPTION FROM THE PROVISIONS OF SECTION 5 OF THE SECURITIES ACT PROVIDED BY RULE 144A THEREUNDER.]***

[THE HOLDER OF THIS SERIES E SENIOR NOTE AGREES FOR THE BENEFIT OF THE COMPANY THAT (A) THIS SERIES E SENIOR NOTE MAY BE OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED, ONLY (I) IN THE UNITED STATES TO A PERSON WHOM THE SELLER REASONABLY BELIEVES IS A

** Insert in Global Securities.

*** Insert in Restricted Securities

QUALIFIED INSTITUTIONAL BUYER (AS DEFINED IN RULE 144A UNDER THE SECURITIES ACT) IN A TRANSACTION MEETING THE REQUIREMENTS OF RULE 144A, (II) OUTSIDE THE UNITED STATES IN AN OFFSHORE TRANSACTION IN ACCORDANCE WITH RULE 904 UNDER THE SECURITIES ACT, (III) PURSUANT TO AN EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT PROVIDED BY RULE 144 THEREUNDER (IF AVAILABLE), (IV) PURSUANT TO AN EFFECTIVE REGISTRATION STATEMENT UNDER THE SECURITIES ACT, OR (V) TO AN INSTITUTIONAL “ACCREDITED INVESTOR” (AS DEFINED IN RULE 501(A)(1), (2), (3) OR (7) OF REGULATION D UNDER THE SECURITIES ACT) THAT IS ACQUIRING THE NOTE FOR ITS OWN ACCOUNT, OR FOR THE ACCOUNT OF SUCH AN INSTITUTIONAL “ACCREDITED INVESTOR” FOR INVESTMENT PURPOSES AND NOT WITH A VIEW TO, OR FOR OFFER OR SALE IN CONNECTION WITH, ANY DISTRIBUTION IN VIOLATION OF THE SECURITIES ACT, IN EACH OF CASES (I) THROUGH (V) IN ACCORDANCE WITH ANY APPLICABLE SECURITIES LAWS OF ANY STATE OF THE UNITED STATES, AND (B) THE HOLDER WILL, AND EACH SUBSEQUENT HOLDER IS REQUIRED TO, NOTIFY ANY PURCHASER OF THIS SERIES E SENIOR NOTE FROM IT OF THE RESALE RESTRICTIONS REFERRED TO IN CLAUSE (A) ABOVE.]***

[THE HOLDER AGREES THAT IT WILL DELIVER TO EACH PERSON TO WHOM THIS SERIES E SENIOR NOTE OR AN INTEREST HEREIN IS TRANSFERRED A NOTICE SUBSTANTIALLY TO THE EFFECT OF THIS LEGEND.]***

[THE HOLDER AGREES THAT, BEFORE THE HOLDER OFFERS, SELLS OR OTHERWISE TRANSFERS THIS SERIES E SENIOR NOTE, THE COMPANY MAY REQUIRE THE HOLDER OF THIS SERIES E SENIOR NOTE TO DELIVER A WRITTEN OPINION, CERTIFICATIONS AND/OR OTHER INFORMATION THAT IT REASONABLY REQUIRES TO CONFIRM THAT SUCH PROPOSED TRANSFER IS BEING MADE PURSUANT TO AN EXEMPTION FROM THE REGISTRATION REQUIREMENTS OF THE UNITED STATES.]***

[AS USED IN THIS SERIES E SENIOR NOTE, THE TERMS “OFFSHORE TRANSACTION,” “U.S. PERSON” AND “UNITED STATES” HAVE THE MEANINGS GIVEN TO THEM BY RULE 902 OF REGULATION S UNDER THE SECURITIES ACT.]***

DOMINION RESOURCES, INC.

[Up to]** $        

2016 SERIES E 1.50% SENIOR NOTE

DUE 2018

No. R-                                                                                                                                                                     CUSIP No.                     

Dominion Resources, Inc., a corporation duly organized and existing under the laws of Virginia (herein called the “Company”, which term includes any successor Person under the

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Indenture hereinafter referred to), for value received, hereby promises to pay to [Cede & Co.]**, or registered assigns (the “Holder”), the principal sum [of                      Dollars ($        )] [specified in Schedule I hereto]** on September 30, 2018 and to pay interest thereon from September 28, 2016 or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semi-annually in arrears on March 30 and September 30 of each year, commencing on March 30, 2017, at the rate of 1.50% per annum, until the principal hereof is paid or made available for payment, provided that any principal, and any such installment of interest, that is overdue shall bear interest at the rate of 1.50% per annum (to the extent that the payment of such interest shall be legally enforceable), from the dates such amounts are due until they are paid or made available for payment, and such interest shall be payable on demand. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in such Indenture, be paid to the Person in whose name this Series E Senior Note (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest; provided that the interest payable at Stated Maturity or on a Redemption Date will be paid to the Person to whom principal is payable. The Regular Record Date shall be the close of business on the Business Day preceding such Interest Payment Date; provided, that with respect to Series E Senior Notes that are not represented by one or more Global Securities, the Regular Record Date shall be the close of business on the fifteenth (15^th) calendar day (whether or not a Business Day) preceding such Interest Payment Date. Any such interest not so punctually paid or duly provided for will forthwith cease to be payable to the Holder on such Regular Record Date and may either be paid to the Person in whose name this Series E Senior Note (or one or more Predecessor Securities) is registered at the close of business on a Special Record Date for the payment of such Defaulted Interest to be fixed by the Trustee, notice whereof shall be given to Holders of Series E Senior Notes not less than 10 days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange on which the Series E Senior Notes may be listed, and upon such notice as may be required by such exchange, all as more fully provided in said Indenture.

Payments of interest on the Series E Senior Notes will include interest accrued to but excluding the respective Interest Payment Dates. Interest payments for the Series E Senior Notes shall be computed and paid on the basis of a 360-day year of twelve 30-day months. In the event that any date on which interest is payable on the Series E Senior Notes is not a Business Day, then payment of the interest payable on such date will be made on the next succeeding day that is a Business Day (and without any interest or payment in respect of any such delay), in each case with the same force and effect as if made on the date the payment was originally payable.

Payment of the principal of and interest on this Series E Senior Note will be made at the office of the Paying Agent, in the Borough of Manhattan, City and State of New York, in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts, with any such payment that is due at the Stated Maturity of any Series E Senior Note, upon redemption or repurchase being made upon surrender of such Series E Senior Note to such office or agency; provided, however, that at the option of the Company payment of interest, subject to such surrender where applicable, may be made (i) by check mailed to the address of the Person entitled thereto as such address shall appear in the Security Register or (ii) by wire transfer at such place and to such account at a banking institution in the United States as may be designated in writing to the Trustee at least sixteen (16) days

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prior to the date for payment by the Person entitled thereto. In the event that any date on which principal and interest is payable on the Series E Senior Notes is not a Business Day, then payment of the principal and interest payable on such date will be made on the next succeeding day that is a Business Day (and without any interest or payment in respect of any such delay), in each such case with the same force and effect as if made on the date the payment was originally payable.

Reference is hereby made to the further provisions of this Series E Senior Note set forth on the reverse hereof, which further provisions shall for all purposes have the same effect as if set forth at this place.

Unless the certificate of authentication hereon has been executed by the Trustee referred to on the reverse hereof by manual signature, this Series E Senior Note shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose.

IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed.

Dated:	DOMINION RESOURCES, INC.
	By:
	Name:
	Title:

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[REVERSE OF 2016 SERIES E 1.50% SENIOR NOTE]

This Security is one of a duly authorized issue of securities of the Company (herein called the “Securities”), issued and to be issued in one or more series under an Indenture dated as of June 1, 2015 (the “Base Indenture”), between the Company and Deutsche Bank Trust Company Americas, as Trustee (the “Trustee”), as heretofore supplemented and as further supplemented by a Seventh Supplemental Indenture dated as of September 1, 2016 (the “Seventh Supplemental Indenture” and, together with the Base Indenture, as it may be hereafter supplemented or amended from time to time, the “Indenture,” which term shall have the meaning assigned to it in such instrument), by and between the Company and the Trustee, and reference is hereby made to the Indenture for a statement of the respective rights, limitations of rights, duties and immunities thereunder of the Company, the Trustee and the Holders of the Securities and of the terms upon which the Securities are, and are to be, authenticated and delivered. This Security is one of the series designated on the face hereof (the “Series E Senior Notes”) which is unlimited in aggregate principal amount.

The Series E Senior Notes are redeemable, in whole or in part, at any time and from time to time in the manner and with the effect provided in the Indenture.

If an Event of Default with respect to Series E Senior Notes shall occur and be continuing, the principal of the Series E Senior Notes may be declared due and payable in the manner and with the effect provided in the Indenture.

The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Securities of each series to be affected under the Indenture at any time by the Company and the Trustee for the series of Securities affected, with the consent of the Holders of a majority in principal amount of the Securities at the time Outstanding of each series to be affected. The Indenture also contains provisions permitting the Holders of specified percentages in principal amount of the Securities of each series at the time Outstanding, on behalf of the Holders of all Securities of such series, to waive certain past defaults under the Indenture and their consequences. Any such consent or waiver by the Holder of this Series E Senior Note shall be conclusive and binding upon such Holder and upon all future Holders of this Series E Senior Note and of any Series E Senior Note issued upon the registration of transfer hereof or in exchange therefor or in lieu hereof, whether or not notation of such consent or waiver is made upon this Series E Senior Note.

As provided in and subject to the provisions of the Indenture, the Holder of this Series E Senior Note shall not have the right to institute any proceeding with respect to the Indenture or for the appointment of a receiver or trustee or for any other remedy thereunder, unless such Holder shall have previously given the Trustee written notice of a continuing Event of Default with respect to the Series E Senior Notes, the Holders of not less than a majority in principal amount of the Series E Senior Notes at the time Outstanding shall have made written request to the Trustee to institute proceedings in respect of such Event of Default as Trustee and offered the Trustee indemnity or security reasonably satisfactory to it, and the Trustee shall not have received from the Holders of a majority in principal amount of Series E Senior Notes at the time Outstanding a direction inconsistent with such request, and shall have failed to institute any such

5

proceeding for 60 days after receipt of such notice, request and offer of indemnity. The foregoing shall not apply to any suit instituted by the Holder of this Series E Senior Note for the enforcement of any payment of principal hereof or premium, if any, or interest hereon on or after the respective due dates expressed or provided for herein.

No reference herein to the Indenture and no provision of this Series E Senior Note or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of, premium, if any, and interest on this Series E Senior Note at the times, place and rate, and in the coin or currency, herein prescribed.

As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Series E Senior Note is registrable in the Security Register, upon surrender of this Series E Senior Note for registration of transfer at the office or agency of the Company in any place where the principal of, premium, if any, and interest on this Series E Senior Note are payable, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed by, the Holder hereof or his attorney duly authorized in writing, and thereupon one or more new Series E Senior Notes of like tenor, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees.

The Series E Senior Notes are issuable only in registered form without coupons in denominations of $2,000 and any greater integral multiple of $1,000. As provided in the Indenture and subject to certain limitations therein set forth, Series E Senior Notes are exchangeable for a like aggregate principal amount of Series E Senior Notes having the same Stated Maturity and of like tenor of any authorized denominations as requested by the Holder upon surrender of the Series E Senior Note or Series E Senior Notes to be exchanged at the office or agency of the Company.

No service charge shall be made for any such registration of transfer or exchange, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith.

Prior to due presentment of this Series E Senior Note for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Series E Senior Note be overdue, and neither the Company, the Trustee nor any such agent shall be affected by notice to the contrary.

All terms used in this Series E Senior Note that are defined in the Indenture shall have the meanings assigned to them in the Indenture.

6

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this instrument, shall be construed as though they were written out in full according to applicable laws or regulations:

TEN COM -	as tenants in common
TEN ENT -	as tenants by the entireties
JT TEN -	as joint tenants with rights of survivorship and not as tenants in common
UNIF GIFT MIN ACT -	Custodian for
	(Cust)
	(Minor)
	Under Uniform Gifts to Minors Act of
	(State)

Additional abbreviations may also be used though not on the above list.

7

FOR VALUE RECEIVED, the undersigned hereby sell(s) and transfer(s) unto

.

(please insert Social Security or other identifying number of assignee)

.

.

.

PLEASE PRINT OR TYPEWRITE NAME AND ADDRESS, INCLUDING POSTAL ZIP CODE OF ASSIGNEE

the within Series E Senior Note and all rights thereunder, hereby irrevocably constituting and appointing

.

.

.

.

.

.

agent to transfer said Series E Senior Note on the books of the Company, with full power of substitution in the premises.

Dated:              ,         

NOTICE: The signature to this assignment must correspond with the name as written upon the face of the within instrument in every particular without alteration or enlargement, or any change whatever.

8

DOMINION RESOURCES, INC.

2016 SERIES E SENIOR NOTE

DUE 2018

No. R-     

SCHEDULE I**

The initial principal amount of this Series E Senior Note is: $        

The following increases or decreases in this Global Security have been made:

Date of increase or decrease and reason for the change in principal amount Amount of decrease in principal amount of this Global Security Amount of increase in principal amount of this Global Security Principal amount of this Global Security following such decrease or increase Signature of authorized signatory of Trustee

9

EXHIBIT B

CERTIFICATE OF AUTHENTICATION

This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.

DEUTSCHE BANK TRUST COMPANY AMERICAS, as Trustee
By:
	Authorized Signatory
Dated:

10

EX-12.1

Exhibit 12.1

Dominion Resources, Inc. and Subsidiaries

Computation of Ratio of Earnings to Fixed Charges

(millions of dollars)

						Years Ended December 31,
	Nine Months Ended September 30, 2016(a)			Twelve Months Ended September 30, 2016(b)		2015(c)		2014(d)			2013(e)		2012(f)			2011(g)
Earnings, as defined:
Income from continuing operations including noncontrolling interest before income tax expense	$	2,282		$	2,760	$	2,828	$	1,778		$	2,704	$	2,265		$	2,262
Distributed income from unconsolidated investees, less equity in earnings		(12	)		2		12		(8	)		17		(13	)		(23	)
Fixed charges included in income		756			1000		953		1,237			930		880			867
Total earnings, as defined	$	3,026		$	3,762	$	3,793	$	3,007		$	3,651	$	3,132		$	3,106
Fixed charges, as defined:
Interest charges	$	731		$	966	$	920	$	1,208		$	899	$	845		$	818
Rental interest factor		25			34		33		29			31		35			49
Fixed charges included in income	$	756		$	1000	$	953	$	1,237		$	930	$	880		$	867
Preference security dividend requirement of consolidated subsidiary	$	—		$	—	$	—	$	17		$	25	$	25		$	25
Capitalized Interest	$	93		$	116	$	67	$	39		$	28	$	24		$	11
Interest from discontinued operations	$	—		$	—	$	—	$	—		$	85	$	80		$	99
Total fixed charges, as defined	$	849		$	1,116	$	1,020	$	1,293		$	1,068	$	1,009		$	1,002
Ratio of Earnings to Fixed Charges		3.56			3.37		3.72		2.33			3.42		3.10			3.10

(a) Earnings for the nine months ended September 30, 2016 include $65 million charge associated with an organizational design initiative; $60 million in transaction and transition costs associated with the Dominion Questar combination; $18 million charge related to other items; partially offset by $29 million of net gain related to our investments in nuclear decommissioning trust funds. Excluding the effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the nine months ended September 30, 2016.

(b) Earnings for the twelve months ended September 30, 2016 include $65 million charge associated with an organizational design initiative; $60 million in transaction and transition costs associated with the Dominion Questar combination; $54 million charge associated with ash pond and landfill closure costs; $82 million charge related to other items; partially offset by $50 million of net gain related to our investments in nuclear decommissioning trust. Excluding the effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended September 30, 2016.

(c) Earnings for the twelve months ended December 31, 2015 include $85 million write-off of prior-period deferred fuel costs associated with Virginia legislation; $99 million charge associated with ash pond and landfill closure costs and $78 million charge related to other items; partially offset by $60 million of net gain related to our investments in nuclear decommissioning trust funds. Excluding the effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2015.

(d) Earnings for the twelve months ended December 31, 2014 include $374 million charge related to North Anna and offshore wind facilities; $284 million charge associated with our liability management effort, which is included in fixed charges; $121 million accrued charge associated with ash pond and landfill closure costs; $93 million charge related to other items; partially offset by $100 million net gain on the sale of our electric retail energy marketing business and $72 million of net gain related to our investments in nuclear decommissioning trust funds. Excluding the effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2014.

(e) Earnings for the twelve months ended December 31, 2013 include a $55 million impairment charge related to certain natural gas infrastructure assets; $40 million charge in connection with the Virginia Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2011-2012 test years; $28 million charge associated with our operating expense reduction initiative, primarily reflecting severance pay and other employee related costs; $26 million charge related to the expected early shutdown of certain coal-fired generating units; $29 million charge related to other items ; partially offset by $81 million of net gain related to our investments in nuclear decommissioning trust funds; $47 million benefit due to a downward revision in the nuclear decommissioning asset retirement obligations for certain merchant nuclear units that are no longer in service; $29 million net benefit primarily resulting from the sale of Elwood. Excluding the net effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2013.

(f) Earnings for the twelve months ended December 31, 2012 include $438 million of impairment and other charges related the planned shut-down of Kewaunee; $87 million of restoration costs associated with severe storms affecting our Dominion Virginia Power and Dominion North Carolina service territories; partially offset by a $36 million net gain related to our investments in nuclear decommissioning trust funds and $4 million net benefit related to other items. Excluding the net effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2012.

(g) Earnings for the twelve months ended December 31, 2011 include $228 million of impairment charges related to electric utility generation assets; $96 million of restoration costs associated with Hurricane Irene; $43 million impairment of excess emission allowances resulting from a new EPA Air Pollution Rule; $31 million net charge in connection with the Virginia State Corporation Commission’s final ruling associated with its biennial review of Virginia Power’s base rates for 2009 and 2010 test years; $21 million of earthquake related costs, largely related to inspections following the safe shutdown of reactors at our North Anna nuclear power station; and a $45 million net charge related to other items; partially offset by a $24 million benefit related to litigation with the Department of Energy for spent nuclear fuel-related costs at our Millstone nuclear power station. Excluding the net effect of these items from the calculation would result in a higher ratio of earnings to fixed charges for the twelve months ended December 31, 2011.

EX-12.2

Exhibit 12.2

Virginia Electric and Power Company

Computation of Ratio of Earnings to Fixed Charges

(millions of dollars)

					Years Ended December 31,
	Nine Months Ended September 30, 2016		Twelve Months Ended September 30, 2016		2015		2014		2013		2012		2011
Earnings, as defined:
Income from continuing operations before income tax expense	$	1,683	$	1,965	$	1,746	$	1,406	$	1,797	$	1,703	$	1,362
Fixed charges included in income		369		489		474		438		401		418		361
Total earnings, as defined	$	2,052	$	2,454	$	2,220	$	1,844	$	2,198	$	2,121	$	1,723
Fixed charges, as defined:
Interest charges	$	356	$	471	$	457	$	425	$	388	$	404	$	346
Rental interest factor		13		18		17		13		13		14		15
Total fixed charges, as defined	$	369	$	489	$	474	$	438	$	401	$	418	$	361
Ratio of Earnings to Fixed Charges		5.56		5.02		4.68		4.21		5.48		5.07		4.77

EX-12.3

Exhibit 12.3

Dominion Gas Holdings, LLC

Computation of Ratio of Earnings to Fixed Charges

(millions of dollars)

						Years Ended December 31,
	Nine Months Ended September 30, 2016		Twelve Months Ended September 30, 2016			2015			2014			2013			2012		2011
Earnings, as defined:
Income from continuing operations before income tax expense	$	448	$	597		$	740		$	846		$	762		$	747	$	549
Distributed income from unconsolidated investees, less equity in earnings		3		(1	)		(3	)		(1	)		(2	)		2		2
Fixed charges included in income		79		104			86			39			43			65		64
Total earnings, as defined	$	530	$	700		$	823		$	884		$	803		$	814	$	615
Fixed charges, as defined:
Interest charges	$	70	$	91		$	74		$	28		$	30		$	51	$	51
Rental interest factor		9		13			12			11			13			14		13
Total fixed charges, as defined	$	79	$	104		$	86		$	39		$	43		$	65	$	64
Ratio of Earnings to Fixed Charges		6.71		6.73			9.57			22.67			18.67			12.52		9.61

EX-31.A

Exhibit 31.a

I, Thomas F. Farrell II, certify that:

1. I have reviewed this report on Form 10-Q of Dominion Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 9, 2016	/s/ Thomas F. Farrell II
	Thomas F. Farrell II President and Chief Executive Officer

EX-31.B

Exhibit 31.b

I, Mark F. McGettrick, certify that:

1. I have reviewed this report on Form 10-Q of Dominion Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 9, 2016	/s/ Mark F. McGettrick
	Mark F. McGettrick Executive Vice President and Chief Financial Officer

EX-31.C

Exhibit 31.c

I, Thomas F. Farrell II, certify that:

1. I have reviewed this report on Form 10-Q of Virginia Electric and Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 9, 2016	/s/ Thomas F. Farrell II
	Thomas F. Farrell II Chief Executive Officer

EX-31.D

Exhibit 31.d

I, Mark F. McGettrick, certify that:

1. I have reviewed this report on Form 10-Q of Virginia Electric and Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 9, 2016	/s/ Mark F. McGettrick
	Mark F. McGettrick Executive Vice President and Chief Financial Officer

EX-31.E

Exhibit 31.e

I, Thomas F. Farrell II, certify that:

1. I have reviewed this report on Form 10-Q of Dominion Gas Holdings, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 9, 2016	/s/ Thomas F. Farrell II
	Thomas F. Farrell II Chief Executive Officer

EX-31.F

Exhibit 31.f

I, Mark F. McGettrick, certify that:

1. I have reviewed this report on Form 10-Q of Dominion Gas Holdings, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 9, 2016	/s/ Mark F. McGettrick
	Mark F. McGettrick Executive Vice President and Chief Financial Officer

EX-32.A

Exhibit 32.a

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned officers of Dominion Resources, Inc. (the “Company”), certify that:

1. the Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 (the “Report”), of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of September 30, 2016, and for the period then ended.

/s/ Thomas F. Farrell II

Thomas F. Farrell II

President and Chief Executive Officer

November 9, 2016

/s/ Mark F. McGettrick

Mark F. McGettrick

Executive Vice President and

Chief Financial Officer

November 9, 2016

EX-32.B

Exhibit 32.b

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned officers of Virginia Electric and Power Company (the “Company”), certify that:

1. the Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 (the “Report”), of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of September 30, 2016, and for the period then ended.

/s/ Thomas F. Farrell II                                

Thomas F. Farrell II

Chief Executive Officer

November 9, 2016

/s/ Mark F. McGettrick                                

Mark F. McGettrick

Executive Vice President and

Chief Financial Officer

November 9, 2016

EX-32.C

Exhibit 32.c

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned officers of Dominion Gas Holdings, LLC (the “Company”), certify that:

1. the Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 (the “Report”), of the Company to which this certification is an exhibit fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)).

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of September 30, 2016, and for the period then ended.

/s/ Thomas F. Farrell II                                

Thomas F. Farrell II

Chief Executive Officer

November 9, 2016

/s/ Mark F. McGettrick                                

Mark F. McGettrick

Executive Vice President and

Chief Financial Officer

November 9, 2016

EX-99

Exhibit 99

DOMINION RESOURCES, INC.

CONDENSED CONSOLIDATED EARNINGS STATEMENT

(Unaudited)

	Twelve Months Ended September 30, 2016
(millions, except per share amounts)
Operating Revenue	$	11,208
Operating Expenses		7,761
Income from operations		3,447
Other income		258
Interest and related charges		945
Income from operations including noncontrolling interests before income tax expense		2,760
Income tax expense		673
Net income including noncontrolling interests		2,087
Noncontrolling interests		64
Net income Attributable to Dominion	$	2,023
Earnings Per Common Share – Basic
Income from operations	$	3.43
Noncontrolling interests		(0.11	)
Net income attributable to Dominion	$	3.32
Earnings Per Common Share – Diluted
Income from operations	$	3.42
Noncontrolling interests		(0.10	)
Net income attributable to Dominion	$	3.32

DOMINION GAS HOLDINGS, LLC

CONDENSED CONSOLIDATED EARNINGS STATEMENT

(Unaudited)

	Twelve Months Ended September 30, 2016
(millions)
Operating Revenue	$	1,606
Operating Expenses		948
Income from operations		658
Other income		28
Interest and related charges		89
Income before income tax expense		597
Income tax expense		211
Net Income	$	386

VIRGINIA ELECTRIC AND POWER COMPANY

CONDENSED CONSOLIDATED EARNINGS STATEMENT

(Unaudited)

	Twelve Months Ended September 30, 2016
(millions)
Operating Revenue	$	7,492
Operating Expenses		5,137
Income from operations		2,355
Other income		66
Interest and related charges		456
Income before income tax expense		1,965
Income tax expense		733
Net Income	$	1,232

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 15, 2016
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Trading Symbol	D
Entity Registrant Name	DOMINION RESOURCES INC /VA/
Entity Central Index Key	0000715957
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		626,750,459
Virginia Electric and Power Company
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Trading Symbol	VEL - PE
Entity Registrant Name	VIRGINIA ELECTRIC & POWER CO
Entity Central Index Key	0000103682
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		274,723
Dominion Gas Holdings, LLC
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Entity Registrant Name	Dominion Gas Holdings, LLC
Entity Central Index Key	0001603291
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0

XML

Consolidated Statements of Income (Unaudited) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Operating Revenue		$ 3,132	$ 2,971	$ 8,651	$ 9,127
Operating Expenses
Electric fuel and other energy-related purchases		606	636	1,791	2,180
Purchased (excess) electric capacity		(6)	75	107	259
Purchased gas		77	85	252	446
Other operations and maintenance		765	564	2,133	1,875
Depreciation, depletion and amortization		400	355	1,112	1,037
Other taxes		145	133	448	432
Total operating expenses		1,987	1,848	5,843	6,229
Income from operations		1,145	1,123	2,808	2,898
Other income		63	11	189	127
Interest and related charges		250	230	715	674
Income from operations including noncontrolling interests before income tax expense		958	904	2,282	2,351
Income tax expense		230	305	561	794
Net Income Including Noncontrolling Interests		728	599	1,721	1,557
Noncontrolling Interests		38	6	55	15
Net Income Attributable to Dominion		$ 690	$ 593	$ 1,666	$ 1,542
Earnings Per Common Share
Net income attributable to Dominion - Basic (in dollars per share)		$ 1.10	$ 1.00	$ 2.72	$ 2.61
Net income attributable to Dominion - Diluted (in dollars per share)		1.10	1.00	2.71	2.60
Dividends Declared Per Common Share (dollars per share)		$ 0.7000	$ 0.6475	$ 2.1000	$ 1.9425
Virginia Electric and Power Company
Operating Revenue	[1]	$ 2,211	$ 2,058	$ 5,877	$ 6,008
Operating Expenses
Electric fuel and other energy-related purchases	[1]	516	554	1,527	1,861
Purchased (excess) electric capacity		(6)	75	107	259
Affiliated suppliers		73	64	238	208
Other		370	311	1,041	1,008
Depreciation, depletion and amortization		270	244	765	713
Other taxes		74	69	218	212
Total operating expenses		1,297	1,317	3,896	4,261
Income from operations		914	741	1,981	1,747
Other income		13	13	47	49
Interest and related charges		118	116	345	332
Income from operations including noncontrolling interests before income tax expense		809	638	1,683	1,464
Income tax expense		306	253	637	564
Net Income Attributable to Dominion		503	385	1,046	900
Dominion Gas Holdings, LLC
Operating Revenue	[2]	382	365	1,181	1,291
Operating Expenses
Purchased gas	[2]	21	8	71	103
Other energy-related purchases		4	4	8	17
Affiliated suppliers		20	12	63	50
Other		113	51	268	211
Depreciation, depletion and amortization		55	53	150	157
Other taxes		36	35	127	127
Total operating expenses		249	163	687	665
Income from operations		133	202	494	626
Other income		7	4	22	17
Interest and related charges		23	18	68	53
Income from operations including noncontrolling interests before income tax expense		117	188	448	590
Income tax expense		34	77	162	233
Net Income Attributable to Dominion		$ 83	$ 111	$ 286	$ 357

[1] See Note 17 for amounts attributable to affiliates.

[2] See Note 17 for amounts attributable to related parties.

XML

Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net income including noncontrolling interests		$ 728	$ 599	$ 1,721	$ 1,557
Net income		690	593	1,666	1,542
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities	[1]	14	(7)	56	25
Changes in unrealized net gains (losses) on investment securities	[2]	31	(59)	72	(55)
Changes in unrecognized pension and other postretirement benefit costs	[3]	15	(9)	15	(6)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities	[4]	(34)	(53)	(141)	(53)
Net realized gains on investment securities	[5]	(13)	(2)	(23)	(35)
Net pension and other postretirement benefit costs	[6]	9	14	25	39
Changes in other comprehensive income (loss) from equity method investees	[7]	0	1	(1)	0
Total other comprehensive income (loss)		22	(115)	3	(85)
Comprehensive income including noncontrolling interests		750	484	1,724	1,472
Comprehensive income attributable to noncontrolling interests		38	6	55	15
Comprehensive income attributable to Dominion		712	478	1,669	1,457
Virginia Electric and Power Company
Net income		503	385	1,046	900
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities	[8]	(1)	(6)	(16)	(3)
Changes in unrealized net gains (losses) on investment securities	[9]	4	(11)	10	(10)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities	[10]	0	0	0	1
Net realized gains on investment securities	[11]	(1)	(1)	(2)	(4)
Total other comprehensive income (loss)		2	(18)	(8)	(16)
Comprehensive income attributable to Dominion		505	367	1,038	884
Dominion Gas Holdings, LLC
Net income		83	111	286	357
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities	[12]	9	3	(6)	2
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities	[13]	(1)	(2)	(3)	(3)
Net pension and other postretirement benefit costs	[14]	1	1	2	3
Total other comprehensive income (loss)		9	2	(7)	2
Comprehensive income attributable to Dominion		$ 92	$ 113	$ 279	$ 359

[1] Net of $(8) million and $--- million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $(34) million and $(20) million tax for the nine months ended September 30, 2016 and 2015, respectively.

[2] Net of $(18) million and $55 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $(43) million and $50 million tax for the nine months ended September 30, 2016 and 2015, respectively.

[3] Net of $(10) million and $(9) million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $(10) million and $(6) million tax for the nine months ended September 30, 2016 and 2015, respectively.

[4] Net of $21 million and $30 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $88 million and $34 million tax for the nine months ended September 30, 2016 and 2015, respectively.

[5] Net of $7 million and $--- million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $13 million and $20 million tax for the nine months ended September 30, 2016 and 2015, respectively.

[6] Net of $(4) million and $(7) million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $(16) million and $(25) million tax for the nine months ended September 30, 2016 and 2015, respectively.

[7] Net of $--- million and $(1) million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $--- million tax for both the nine months ended September 30, 2016 and 2015.

[8] Net of $1 million and $3 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $10 million and $1 million tax for the nine months ended September 30, 2016 and 2015, respectively.

[9] Net of $(2) million and $5 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $(6) million and$5 million tax for the nine months ended September 30, 2016 and 2015, respectively.

[10] Net of $--- million tax for both the three months ended September 30, 2016 and 2015, and net of $(1) million and $--- million tax for the nine months ended September 30, 2016 and 2015, respectively.

[11] Net of $1 million and $2 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $2 million and $3 million tax for the nine months ended September 30, 2016 and 2015, respectively.

[12] Net of $(3) million and $(1) million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $5 million and $--- million tax for the nine months ended September 30, 2016 and 2015, respectively.

[13] Net of $2 million and $1 million tax for the three months ended September 30, 2016 and 2015, respectively, and net of $2 million and $1 million tax for the nine months ended September 30, 2016 and 2015, respectively.

[14] Net of $(1) million tax for both the three months ended September 30, 2016 and 2015, and net of $(2) million and $(3) million tax for the nine months ended September 30, 2016 and 2015, respectively.

XML

Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net deferred gains (losses) on derivative-hedging activities, tax	$ (8)	$ 0	$ (34)	$ (20)
Changes in unrealized net gains (losses) on investment securities, tax	(18)	55	(43)	50
Changes in unrecognized pension and other postretirement benefit costs, tax	(10)	(9)	(10)	(6)
Net derivative (gains) losses-hedging activities, tax	21	30	88	34
Net realized gains on investment securities, tax	7	0	13	20
Net pension and other postretirement benefit costs, tax	(4)	(7)	(16)	(25)
Changes in other comprehensive income (loss) from equity method investees, tax	0	(1)	0	0
Virginia Electric and Power Company
Net deferred gains (losses) on derivative-hedging activities, tax	1	3	10	1
Changes in unrealized net gains (losses) on investment securities, tax	(2)	5	(6)	5
Net derivative (gains) losses-hedging activities, tax	0	0	(1)	0
Net realized gains on investment securities, tax	1	2	2	3
Dominion Gas Holdings, LLC
Net deferred gains (losses) on derivative-hedging activities, tax	(3)	(1)	5	0
Net derivative (gains) losses-hedging activities, tax	2	1	2	1
Net pension and other postretirement benefit costs, tax	$ (1)	$ (1)	$ (2)	$ (3)

XML

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents		$ 251	$ 607	[1]
Customer receivables (less allowance for doubtful accounts)		1,259	1,200	[1]
Other receivables (less allowance for doubtful accounts)		133	169	[1]
Inventories		1,516	1,348	[1]
Prepayments		147	198	[1]
Regulatory assets	[2]	250	351
Other		493	667	[1]
Total current assets		3,799	4,189	[1]
Investments
Nuclear decommissioning trust funds		4,427	4,183	[1]
Investment in equity method affiliates		1,498	1,320	[1]
Other		299	271	[1]
Total investments		6,224	5,774	[1]
Property, Plant and Equipment
Property, plant and equipment		68,282	57,776	[1]
Accumulated depreciation, depletion and amortization		(19,394)	(16,222)	[1]
Total property, plant and equipment, net		48,888	41,554	[1]
Deferred Charges and Other Assets
Goodwill		6,405	3,294	[1]
Pension and other postretirement benefit assets		1,095	943	[1]
Regulatory assets		2,143	1,865	[1]
Other		1,045	1,029	[1]
Total deferred charges and other assets		10,688	7,131	[1]
Total assets		69,599	58,648	[1]
Current Liabilities
Securities due within one year		2,931	1,825	[1]
Short-term debt		3,097	3,509	[1]
Accounts payable		685	726	[1]
Accrued interest, payroll and taxes		800	515	[1]
Regulatory liabilities	[3]	124	100
Other	[4]	1,514	1,544	[1]
Total current liabilities		9,027	8,119	[1]
Long-Term Debt
Long-term debt		23,356	20,048	[1]
Junior subordinated notes		2,980	1,340	[1]
Remarketable subordinated notes		2,371	2,080	[1]
Total long-term debt		28,707	23,468	[1]
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		8,675	7,414	[1]
Asset retirement obligations		2,153	1,887	[1]
Regulatory liabilities		2,597	2,285	[1]
Other		2,248	1,873	[1]
Total deferred credits and other liabilities		15,673	13,459	[1]
Total liabilities		53,407	45,046	[1]
Commitments and Contingencies				[1]
Equity
Common stock - no par	[5]	8,592	6,680	[1]
Retained earnings		6,837	6,458	[1]
Accumulated other comprehensive loss		(471)	(474)	[1]
Total common shareholders' equity		14,958	12,664	[1]
Noncontrolling interests		1,234	938	[1]
Total equity		16,192	13,602	[1]
Total liabilities and equity		69,599	58,648	[1]
Virginia Electric and Power Company
Current Assets
Cash and cash equivalents		18	18	[6]
Customer receivables (less allowance for doubtful accounts)		937	822	[6]
Other receivables (less allowance for doubtful accounts)		87	109	[6]
Affiliated receivables		1	296	[6]
Inventories		836	873	[6]
Prepayments		23	38	[6]
Regulatory assets		197	326	[6]
Other	[7]	33	22	[6]
Total current assets		2,132	2,504	[6]
Investments
Nuclear decommissioning trust funds		2,074	1,945	[6]
Other		3	3	[6]
Total investments		2,077	1,948	[6]
Property, Plant and Equipment
Property, plant and equipment		39,428	37,639	[6]
Accumulated depreciation, depletion and amortization		(12,314)	(11,708)	[6]
Total property, plant and equipment, net		27,114	25,931	[6]
Deferred Charges and Other Assets
Regulatory assets		897	667	[6]
Other	[7]	527	515	[6]
Total deferred charges and other assets		1,424	1,182	[6]
Total assets		32,747	31,565	[6]
Current Liabilities
Securities due within one year		679	476	[6]
Short-term debt		965	1,656	[6]
Accounts payable		330	366	[6]
Accrued interest, payroll and taxes		321	190	[6]
Regulatory liabilities		75	35	[6]
Payables to affiliates		84	73	[6]
Affiliated current borrowings		0	376	[6]
Other	[7]	690	558	[6]
Total current liabilities		3,144	3,730	[6]
Long-Term Debt
Total long-term debt		8,963	8,892	[6]
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		5,017	4,654	[6]
Asset retirement obligations		1,194	1,104	[6]
Regulatory liabilities		1,967	1,929	[6]
Other	[7]	784	615	[6]
Total deferred credits and other liabilities		8,962	8,302	[6]
Total liabilities		21,069	20,924	[6]
Commitments and Contingencies				[6]
Equity
Common stock - no par	[8]	5,738	5,738	[6]
Other paid-in capital		1,113	1,113	[6]
Retained earnings		4,795	3,750	[6]
Accumulated other comprehensive loss		32	40	[6]
Total common shareholders' equity		11,678	10,641	[6]
Total liabilities and equity		32,747	31,565	[6]
Dominion Gas Holdings, LLC
Current Assets
Cash and cash equivalents		8	13	[9]
Customer receivables (less allowance for doubtful accounts)	[10]	158	219	[9]
Other receivables (less allowance for doubtful accounts)	[10]	12	7	[9]
Affiliated receivables		5	98	[9]
Inventories		94	78	[9]
Prepayments		73	88	[9]
Regulatory assets	[2]	22	23
Other	[10]	55	63	[9]
Total current assets		405	566	[9]
Investments
Total investments		98	104	[9]
Property, Plant and Equipment
Property, plant and equipment		10,259	9,693	[9]
Accumulated depreciation, depletion and amortization		(2,808)	(2,690)	[9]
Total property, plant and equipment, net		7,451	7,003	[9]
Deferred Charges and Other Assets
Goodwill		542	542	[9]
Regulatory assets	[11]	469	449
Pension and other postretirement benefit assets	[10]	1,613	1,510	[9]
Other	[10]	634	583	[9]
Total deferred charges and other assets		2,789	2,635	[9]
Total assets		10,743	10,308	[9]
Current Liabilities
Securities due within one year		400	400	[9]
Short-term debt		60	391	[9]
Accounts payable		124	201	[9]
Accrued interest, payroll and taxes		176	183	[9]
Regulatory liabilities	[3]	39	55
Payables to affiliates		20	22	[9]
Affiliated current borrowings		0	95	[9]
Other	[10]	162	183	[9]
Total current liabilities		942	1,475	[9]
Long-Term Debt
Total long-term debt		3,545	2,869	[9]
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,414	2,214	[9]
Regulatory liabilities	[12]	217	201
Other	[10]	395	432	[9]
Total deferred credits and other liabilities		2,809	2,646	[9]
Total liabilities		7,296	6,990	[9]
Commitments and Contingencies				[9]
Equity
Membership interests		3,553	3,417	[9]
Accumulated other comprehensive loss	[10]	(106)	(99)	[9]
Total common shareholders' equity		3,447	3,318	[9]
Total liabilities and equity		$ 10,743	$ 10,308	[9]

[1] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[2] Current regulatory assets are presented in other current assets in Dominion's and Dominion Gas' Consolidated Balance Sheets.

[3] Current regulatory liabilities are presented in other current liabilities in the Dominion's and Dominion Gas' Consolidated Balance Sheets.

[4] See Note 3 for amounts attributable to related parties.

[5] 1 billion shares authorized; 627 million shares and 596 million shares outstanding at September 30, 2016 and December 31, 2015, respectively.

[6] Virginia Power’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[7] See Note 17 for amounts attributable to affiliates.

[8] 500,000 shares authorized; 274,723 shares outstanding at September 30, 2016 and December 31, 2015.

[9] Dominion Gas’ Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[10] See Note 17 for amounts attributable to related parties.

[11] Noncurrent regulatory assets are presented in other deferred charges and other assets in Dominion Gas' Consolidated Balance Sheets

[12] Noncurrent regulatory liabilities are presented in other deferred credits and other liabilities in Dominion Gas' Consolidated Balance Sheets.

XML

Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Customer receivables, allowance for doubtful accounts		$ 18	$ 32	[1]
Other receivables, allowance for doubtful accounts		$ 3	$ 2	[1]
Common stock, shares authorized		1,000,000,000	1,000,000,000	[1]
Common stock, shares outstanding		627,000,000	596,000,000
Virginia Electric and Power Company
Customer receivables, allowance for doubtful accounts		$ 10	$ 27	[1]
Other receivables, allowance for doubtful accounts		$ 1	$ 1	[1]
Common stock, shares authorized		500,000	500,000	[1]
Common stock, shares outstanding		274,723	274,723	[1]
Dominion Gas Holdings, LLC
Customer receivables, allowance for doubtful accounts	[2]	$ 1	$ 1	[3]
Other receivables, allowance for doubtful accounts	[2]	$ 1	$ 2	[3]

[1] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[2] See Note 17 for amounts attributable to related parties.

[3] Dominion Gas’ Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

XML

Consolidated Statement of Equity (Unaudited) - 9 months ended Sep. 30, 2016 - USD ($) shares in Millions, $ in Millions	Total		Total Common Shareholders' Equity	Common Stock	Retained Earnings	Accumulated Other Comprehensive Loss	Noncontrolling Interests
Beginning Balance (in shares) at Dec. 31, 2015				596
Beginning balance at Dec. 31, 2015	$ 13,602	[1]	$ 12,664	$ 6,680	$ 6,458	$ (474)	$ 938
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income including noncontrolling interests	1,721		1,666		1,666		55
Contributions from SunEdison to Four Brothers and Three Cedars	178		0				178
Sale of interest in merchant solar projects	139		22	22			117
Purchase of Dominion Midstream common units	(17)		(3)	$ (3)			(14)
Issuance of common stock (in shares)				31
Issuance of common stock	2,079		2,079	$ 2,079
Stock awards (net of change in unearned compensation)	10		10	10
Present value of stock purchase contract payments related to RSNs	(191)		(191)	(191)
Dividends and distributions	(1,326)		(1,287)		(1,287)		(39)
Other comprehensive income, net of tax	3		3			3
Other	(6)		(5)	$ (5)			(1)
Ending Balance (in shares) at Sep. 30, 2016				627
Ending balance at Sep. 30, 2016	$ 16,192		$ 14,958	$ 8,592	$ 6,837	$ (471)	$ 1,234

[1] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016		Sep. 30, 2015
Operating Activities
Net income including noncontrolling interests	$ 1,721		$ 1,557
Net income	1,666		1,542
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)	1,325		1,250
Deferred income taxes and investment tax credits	481		703
Gains on the sales of assets and equity method investment in Iroquois	(50)		(123)
Other adjustments	(78)		(1)
Changes in:
Accounts receivable	19		229
Inventories	(10)		(3)
Deferred fuel and purchased gas costs, net	84		70
Prepayments	71		45
Accounts payable	(89)		(222)
Accrued interest, payroll and taxes	205		(13)
Margin deposit assets and liabilities	1		205
Other operating assets and liabilities	(294)		(244)
Net cash provided by operating activities	3,386		3,453
Investing Activities
Plant construction and other property additions (including nuclear fuel)	(4,536)		(3,632)
Acquisition of Dominion Questar, net of cash acquired	(4,372)		0
Acquisition of solar development projects	(21)		(278)
Acquisition of DCG	0		(497)
Proceeds from sales of securities	1,009		937
Purchases of securities	(1,065)		(921)
Proceeds from assignments of shale development rights	10		80
Other	(54)		(39)
Net cash used in investing activities	(9,029)		(4,350)
Financing Activities
Issuance (repayment) of short-term debt, net	(713)		(220)
Issuance of short-term notes	1,200		0
Repayment and repurchase of short-term notes	(600)		0
Issuance and remarketing of long-term debt	5,730		2,262
Repayment and repurchase of long-term debt	(1,169)		(675)
Proceeds from sale of interest in merchant solar projects	117		0
Contributions from SunEdison to Four Brothers and Three Cedars	178		0
Issuance of common stock	2,079		717
Common dividend payments	(1,287)		(1,150)
Other	(248)		(117)
Net cash provided by financing activities	5,287		817
Increase (decrease) in cash and cash equivalents	(356)		(80)
Cash and cash equivalents at beginning of period	607	[1]	318
Cash and cash equivalents at end of period	251		238
Significant noncash investing and financing activities:
Accrued capital expenditures	341		389
Dominion Midstream's acquisition of a noncontrolling partnership interest in Iroquois in exchange for issuance of Dominion Midstream common units	0		216
Virginia Electric and Power Company
Operating Activities
Net income	1,046		900
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)	903		844
Deferred income taxes and investment tax credits	369		9
Other adjustments	(15)		20
Changes in:
Accounts receivable	(99)		10
Affiliated receivables and payables	306		(33)
Inventories	37		11
Deferred fuel and purchased gas costs, net	79		40
Prepayments	15		228
Accounts payable	4		(62)
Accrued interest, payroll and taxes	131		137
Other operating assets and liabilities	8		70
Net cash provided by operating activities	2,784		2,174
Investing Activities
Plant construction and other property additions (including nuclear fuel)	(1,835)		(1,840)
Purchases of nuclear fuel	(106)		(100)
Proceeds from sales of securities	478		407
Purchases of securities	(513)		(423)
Other	(11)		(38)
Net cash used in investing activities	(1,987)		(1,994)
Financing Activities
Issuance (repayment) of short-term debt, net	(691)		1
Repayment of affiliated current borrowings, net	(376)		(427)
Issuance and remarketing of long-term debt	750		1,112
Repayment and repurchase of long-term debt	(476)		(421)
Distribution payments to parent	0		(416)
Other	(4)		(5)
Net cash provided by financing activities	(797)		(156)
Increase (decrease) in cash and cash equivalents	0		24
Cash and cash equivalents at beginning of period	18	[2]	15
Cash and cash equivalents at end of period	18		39
Significant noncash investing and financing activities:
Accrued capital expenditures	209		139
Dominion Gas Holdings, LLC
Operating Activities
Net income	286		357
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization	150		157
Deferred income taxes and investment tax credits	204		75
Gains on the sales of assets and equity method investment in Iroquois	(50)		(123)
Other adjustments	3		4
Changes in:
Accounts receivable	56		150
Affiliated receivables and payables	91		(22)
Deferred fuel and purchased gas costs, net	7		19
Prepayments	15		145
Accounts payable	(76)		(112)
Accrued interest, payroll and taxes	(7)		(45)
Other operating assets and liabilities	(176)		(109)
Net cash provided by operating activities	503		496
Investing Activities
Plant construction and other property additions (including nuclear fuel)	(610)		(514)
Proceeds from sale of equity method investment in Iroquois	7		0
Proceeds from assignments of shale development rights	10		80
Other	(10)		(5)
Net cash used in investing activities	(603)		(439)
Financing Activities
Issuance (repayment) of short-term debt, net	(331)		382
Repayment of affiliated current borrowings, net	(95)		(186)
Issuance and remarketing of long-term debt	680		0
Distribution payments to parent	(150)		(244)
Other	(9)		0
Net cash provided by financing activities	95		(48)
Increase (decrease) in cash and cash equivalents	(5)		9
Cash and cash equivalents at beginning of period	13	[3]	9
Cash and cash equivalents at end of period	8		18
Significant noncash investing and financing activities:
Accrued capital expenditures	$ 42		$ 46

[1] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[2] Virginia Power’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[3] Dominion Gas’ Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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Nature of Operations

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

Nature of Operations

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

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Significant Accounting Policies

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Significant Accounting Policies

Significant Accounting Policies

As permitted by the rules and regulations of the SEC, the Companies' accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with GAAP. These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in the Companies' Annual Report on Form 10-K for the year ended December 31, 2015.

In the Companies' opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position as of September 30, 2016, their results of operations for the three and nine months ended September 30, 2016 and 2015, their cash flows for the nine months ended September 30, 2016 and 2015 and Dominion's changes in equity for the nine months ended 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 September 30, 2016, Dominion owns the general partner and 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 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.

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Acquisitions and Dispositions

9 Months Ended

Sep. 30, 2016

Business Combinations, Discontinued Operations and Disposal Groups [Abstract]

Acquisitions and Dispositions

Acquisitions and Dispositions

Dominion

Acquisition of Dominion Questar

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, at closing, each share of issued and outstanding Dominion Questar common stock was converted into the right to receive $25.00 per share in cash. The total consideration was $4.4 billion 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 of 2016 Equity Units, (2) August 2016 issuance of $1.3 billion of senior notes, (3) September 2016 borrowing of $1.2 billion under a private placement term loan agreement and (4) $500 million of the proceeds from the April 2016 issuance of common stock. See Note 14 for more information.

Purchase Price Allocation

Dominion Questar’s assets acquired and liabilities assumed were measured at estimated fair value at the closing date and are included in the Dominion Energy operating segment. The majority of Dominion Questar’s operations are subject to 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 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

(1) Includes $40 million for an equity method investment in White River Hub. The fair value adjustment on the equity method investment in White River Hub is considered to be equity method goodwill and is not amortized.

(2) Nonregulated property, plant and equipment, excluding land, will be depreciated over remaining useful lives primarily ranging from 9 to 18 years.

(3) Includes $301 million of short-term debt, of which $24 million is outstanding at September 30, 2016, as well as a $250 million short-term note which matures in February 2017 and bears interest at a variable rate.

(4) Unsecured senior notes have maturities which range from 2017 to 2048 and bear interest at rates from 2.98% to 7.20%.

(5) Includes a $35 million capital lease obligation with undiscounted future minimum lease payments of $1 million remaining in 2016, $4 million per year for 2017 through 2020, and $37 million in total thereafter.

Regulatory Matters

The transaction required approval of Dominion Questar’s shareholders, clearance from the Federal Trade Commission under the Hart-Scott-Rodino 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 May 2016, Dominion Questar's shareholders voted to approve the Dominion Questar Combination. 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 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:

• Dominion will contribute $75 million toward the funding of Dominion Questar’s qualified and non-qualified defined-benefit pension plans and its other post-employment benefit plans within six months of the closing date. This contribution is expected to be made during the fourth quarter of 2016.

• Dominion committed to increasing Dominion Questar's historical level of corporate contributions to charities by $1 million per year for at least five years.

• Questar Gas withdrew its general rate case filed in July 2016 with the Utah Commission and agreed to not file a general rate case with the Utah Commission to adjust its base distribution non-gas rates prior to July 2019, unless otherwise ordered by the Utah Commission. In addition, Questar Gas agreed not to file a general rate case with the Wyoming Commission with a requested rate effective date earlier than January 2020. This does not impact Questar Gas’s ability to adjust rates through various riders.

Results of Operations and Pro Forma Information

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 transition costs, of which $40 million and $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.

	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

(1) Amounts include adjustments for non-recurring costs directly related to the Dominion Questar Combination.

Anticipated Contribution of Questar Pipeline to Dominion Midstream

In October 2016, Dominion entered into the Contribution Agreement under which Dominion will contribute Questar Pipeline to Dominion Midstream. Upon closing of the 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.

Non-Wholly-Owned Merchant Solar Projects

Acquisitions of Four Brothers and Three Cedars

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 September 30, 2016, a $7 million payable is included in other current liabilities in Dominion's Consolidated Balance Sheets. Four Brothers' purpose is to operate four solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, with generating capacity of approximately 320 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 September 30, 2016, a $4 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Three Cedars’ purpose is to operate three solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, with generating capacity of approximately 210 MW, at a cost of approximately $450 million.

The Four Brothers and Three Cedars facilities operate under long-term power purchase, interconnection and operation and maintenance agreements. Dominion 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 nine months ended September 30, 2016. Subsequent to Dominion’s acquisition of Four Brothers and Three Cedars, SunEdison made contributions to Four Brothers and Three Cedars of $281 million in aggregate through September 30, 2016, which are reflected as noncontrolling interests in Dominion's Consolidated Balance Sheets.

In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison.

Wholly-Owned Merchant Solar Projects

The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion in the 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	Initial Acquisition Cost (millions)(1)		Project Cost (millions)(2)		Date of Commercial Operations	MW Capacity
April 2015	EC&R NA Solar PV, LLC	1	California	Alamo	$	66	$	66	May 2015	20
April 2015	EDF Renewable Development, Inc.	3	California	Cottonwood(3)	106		106		May 2015	24
June 2015	EDF Renewable Development, Inc.	1	California	Catalina 2	68		68		July 2015	18
July 2015	SunPeak Solar, LLC	1	California	Imperial Valley 2	42		71		August 2015	20

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

(2) Includes acquisition cost.

(3) One of the projects, Marin Carport, began commercial operations in 2016.

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.

Sale of Interest in Merchant Solar Projects

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 September 30, 2016 nor are expected to occur in the remainder of 2016.

Acquisition of DCG

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.

Dominion Gas

Assignments of Shale Development Rights

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. Also in connection with that agreement, in July 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. These gains are included in other operations and maintenance expense in Dominion Gas' Consolidated Statements of Income.

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Operating Revenue

9 Months Ended

Sep. 30, 2016

Regulated and Unregulated Operating Revenue [Abstract]

Operating Revenue

Operating Revenue

The Companies’ operating revenue consists of the following:

	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

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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

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
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	%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.7		4.0		3.9		4.2		0.8		4.1
Investment tax credits	(10.4	)	(3.5	)	—		—		—		—
Production tax credits	(0.8	)	(0.8	)	(0.5	)	(0.5	)	—		—
State legislative change	(0.8	)	(0.2	)	—		—		—		—
Other, net	(2.1	)	(0.7	)	(0.5	)	(0.2	)	0.4		0.4
Effective tax rate	24.6	%	33.8	%	37.9	%	38.5	%	36.2	%	39.5	%

In 2016, Dominion's effective tax rate reflects $23 million of 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.

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Earnings Per Share

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions, except EPS)
Net income attributable to Dominion	$	690	$	593	$	1,666	$	1,542
Average shares of common stock outstanding – Basic	625.9		594.6		612.8		591.3
Net effect of dilutive securities(1)	0.1		0.9		1.0		1.4
Average shares of common stock outstanding – Diluted	626.0		595.5		613.8		592.7
Earnings Per Common Share – Basic	$	1.10	$	1.00	$	2.72	$	2.61
Earnings Per Common Share – Diluted	$	1.10	$	1.00	$	2.71	$	2.60

(1) Dilutive securities consist primarily of the 2013 Equity Units for the nine months ended September 30, 2016 and the three and nine months ended September 30, 2015. See Note 14 in this report and Note 17 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 2015 for more information.

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 nine months ended September 30, 2016 and 2015, as the dilutive stock price threshold was not met.

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Accumulated Other Comprehensive Income

9 Months Ended

Sep. 30, 2016

Equity [Abstract]

Accumulated Other Comprehensive Income

Accumulated Other Comprehensive Income

Dominion

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

	Deferred Gains and Losses on Derivatives-Hedging Activities			Unrealized Gains and Losses on Investment Securities			Unrecognized Pension and Other Postretirement Benefit Costs			Other Comprehensive Income (Loss) From Equity Method Investee			Total
(millions)
Three Months Ended 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	$	(146	)	$	519		$	(754	)	$	(5	)	$	(386	)
Other comprehensive income before reclassifications: gains (losses)	(7		)	(59		)	(9		)	1			(74		)
Amounts reclassified from AOCI(1): (gains) losses	(53		)	(2		)	14			—			(41		)
Net current-period other comprehensive income (loss)	(60		)	(61		)	5			1			(115		)
Ending balance	$	(206	)	$	458		$	(749	)	$	(4	)	$	(501	)
Nine Months Ended September 30, 2016
Beginning balance	$	(176	)	$	504		$	(797	)	$	(5	)	$	(474	)
Other comprehensive income before reclassifications: gains (losses)	56			72			15			(1		)	142
Amounts reclassified from AOCI(1): (gains) losses	(141		)	(23		)	25			—			(139		)
Net current-period other comprehensive income (loss)	(85		)	49			40			(1		)	3
Ending balance	$	(261	)	$	553		$	(757	)	$	(6	)	$	(471	)
Nine Months Ended September 30, 2015
Beginning balance	$	(178	)	$	548		$	(782	)	$	(4	)	$	(416	)
Other comprehensive income before reclassifications: gains (losses)	25			(55		)	(6		)	—			(36		)
Amounts reclassified from AOCI(1): (gains) losses	(53		)	(35		)	39			—			(49		)
Net current-period other comprehensive income (loss)	(28		)	(90		)	33			—			(85		)
Ending balance	$	(206	)	$	458		$	(749	)	$	(4	)	$	(501	)

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

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

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

Tax	21			Income tax expense
	$	(34	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(25	)	Other income
Impairment	5			Other income
	(20		)
Tax	7			Income tax expense
	$	(13	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(4	)	Other operations and maintenance
Actuarial (gains) losses	17			Other operations and maintenance
	13
Tax	(4		)	Income tax expense
	$	9
Three Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(87	)	Operating revenue
	2			Purchased gas
Interest rate contracts	2			Interest and related charges
	(83		)
Tax	30			Income tax expense
	$	(53	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(18	)	Other income
Impairment	16			Other income
	(2		)
Tax	—			Income tax expense
	$	(2	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(3	)	Other operations and maintenance
Actuarial (gains) losses	24			Other operations and maintenance
	21
Tax	(7		)	Income tax expense
	$	14
Nine Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(266	)	Operating revenue
	9			Purchased gas
	8			Electric fuel and other energy-related purchases
Interest rate contracts	21			Interest and related charges
Foreign currency contracts	(1		)	Other income
	(229		)
Tax	88			Income tax expense
	$	(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	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(11	)	Other operations and maintenance
Actuarial (gains) losses	52			Other operations and maintenance
	41
Tax	(16		)	Income tax expense
	$	25
Nine Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(103	)	Operating revenue
	9			Purchased gas
Interest rate contracts	7			Interest and related charges
	(87		)
Tax	34			Income tax expense
	$	(53	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(82	)	Other income
Impairment	27			Other income
	(55		)
Tax	20			Income tax expense
	$	(35	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(9	)	Other operations and maintenance
Actuarial (gains) losses	73			Other operations and maintenance
	64
Tax	(25		)	Income tax expense
	$	39

Dominion Gas

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

	Deferred Gains and Losses on Derivatives-Hedging Activities			Unrecognized Pension and Other Postretirement Benefit Costs			Total
(millions)
Three Months Ended September 30, 2016
Beginning balance	$	(34	)	$	(81	)	$	(115	)
Other comprehensive income before reclassifications: gains	9			—			9
Amounts reclassified from AOCI(1): (gains) losses	(1		)	1			—
Net current-period other comprehensive income	8			1			9
Ending balance	$	(26	)	$	(80	)	$	(106	)
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	)
Other comprehensive income before reclassifications: losses	(6		)	—			(6		)
Amounts reclassified from AOCI(1): (gains) losses	(3		)	2			(1		)
Net current-period other comprehensive income (loss)	(9		)	2			(7		)
Ending balance	$	(26	)	$	(80	)	$	(106	)
Nine Months Ended September 30, 2015
Beginning balance	$	(20	)	$	(66	)	$	(86	)
Other comprehensive income before reclassifications: gains	2			—			2
Amounts reclassified from AOCI(1): (gains) losses	(3		)	3			—
Net current-period other comprehensive income (loss)	(1		)	3			2
Ending balance	$	(21	)	$	(63	)	$	(84	)

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

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

Details About AOCI Components	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Three Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(1	)	Operating revenue
Interest rate contracts	1			Interest and related charges
Foreign currency contracts	(3		)	Other income
	(3		)
Tax	2			Income tax expense
	$	(1	)
Unrecognized pension and other postretirement benefit costs:

Actuarial (gains) losses	$	2		Other operations and maintenance
	2
Tax	(1		)	Income tax expense
	$	1
Three Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(3	)	Operating revenue
	(3		)
Tax	1			Income tax expense
	$	(2	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	2		Other operations and maintenance
	2
Tax	(1		)	Income tax expense
	$	1
Nine Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(6	)	Operating revenue
Interest rate contracts	2			Interest and related charges
Foreign currency contracts	(1		)	Other income
	(5		)
Tax	2			Income tax expense
	$	(3	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	4		Other operations and maintenance
	4
Tax	(2		)	Income tax expense
	$	2
Nine Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(4	)	Operating revenue
	(4		)
Tax	1			Income tax expense
	$	(3	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	6		Other operations and maintenance
	6
Tax	(3		)	Income tax expense
	$	3

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Fair Value Measurements

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The Companies' fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 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:

• Foreign currency forward exchange rates

• Credit quality of counterparties and the Companies

• Notional value

• Credit enhancements

• Time value

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. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices, and volumes. For Level 3 fair value measurements, forward market prices, and implied price volatilities are considered unobservable. The unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.

The following table presents Dominion's quantitative information about Level 3 fair value measurements at September 30, 2016. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)	$	85	Discounted cash flow	Market price (per Dth)	(3)	(2) - 7	—
FTRs	7		Discounted cash flow	Market price (per MWh)	(3)	(6) - 6	1
Physical and financial options:
Natural gas	4		Option model	Market price (per Dth)	(3)	2 - 7	3
				Price volatility	(4)	19% - 46%	24	%
Total assets	$	96
Liabilities
Physical and financial forwards and futures:
Natural gas(2)	$	4	Discounted cash flow	Market price (per Dth)	(3)	(2) - 4	1
FTRs	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
				Price volatility	(4)	30% - 46%	38	%
Total liabilities	$	7

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

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

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)
Price volatility	Buy	Increase (decrease)	Gain (loss)
Price volatility	Sell	Increase (decrease)	Loss (gain)

Recurring Fair Value Measurements

Dominion

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

	Level 1		Level 2		Level 3		Total
(millions)
At September 30, 2016
Assets
Derivatives:
Commodity	$	—	$	172	$	96	$	268
Interest rate	—		19		—		19
Foreign currency	—		8		—		8
Investments(1):
Equity securities:
United States:
Large cap	2,712		—		—		2,712
REIT	67		—		—		67
Other	6		—		—		6
Non-United States:
Large cap	10		—		—		10
Fixed income:
Corporate debt instruments	—		518		—		518
United States Treasury securities and agency debentures	438		231		—		669
State and municipal	—		372		—		372
Other	—		109		—		109
Cash equivalents and other	8		—		—		8
Total assets	$	3,241	$	1,429	$	96	$	4,766
Liabilities
Derivatives:
Commodity	$	—	$	104	$	7	$	111
Interest rate	—		307		—		307
Foreign currency	—		4		—		4
Total liabilities	$	—	$	415	$	7	$	422
At December 31, 2015
Assets
Derivatives:
Commodity	$	1	$	249	$	114	$	364
Interest rate	—		24		—		24
Investments(1):
Equity securities:
United States:
Large cap	2,547		—		—		2,547
REIT	63		—		—		63
Other	5		—		—		5
Non-United States:
Large cap	10		—		—		10
Fixed income:

Corporate debt instruments	—		437		—		437
United States Treasury securities and agency debentures	458		201		—		659
State and municipal	—		376		—		376
Other	—		100		—		100
Cash equivalents and other	2		2		—		4
Total assets	$	3,086	$	1,389	$	114	$	4,589
Liabilities
Derivatives:
Commodity	$	—	$	141	$	19	$	160
Interest rate	—		183		—		183
Total liabilities	$	—	$	324	$	19	$	343

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

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

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

	Operating Revenue		Electric Fuel and Other Energy-Related Purchases			Total
(millions)
Three Months Ended September 30, 2016
Total gains (losses) included in earnings	$	—	$	(7	)	$	(7	)
Three Months Ended September 30, 2015
Total gains (losses) included in earnings	$	—	$	(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
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	$	(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

Virginia Power

The following table presents Virginia Power's quantitative information about Level 3 fair value measurements at September 30, 2016. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)	$	81	Discounted cash flow	Market price (per Dth)	(3)	(2) - 7	—
FTRs	7		Discounted cash flow	Market price (per MWh)	(3)	(6) - 6	1
Physical and financial options:
Natural gas	2		Option model	Market price (per Dth)	(3)	2 - 7	3
				Price volatility	(4)	19% - 33%	24	%
Total assets	$	90
Liabilities
Physical and financial forwards and futures:
FTRs	$	2	Discounted cash flow	Market price (per MWh)	(3)	(11) - 6	1
Total liabilities	$	2

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

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

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)
Price volatility	Buy	Increase (decrease)	Gain (loss)
Price volatility	Sell	Increase (decrease)	Loss (gain)

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

	Level 1		Level 2		Level 3		Total
(millions)
At September 30, 2016
Assets
Derivatives:
Commodity	$	—	$	26	$	90	$	116
Interest rate	—		2		—		2
Investments(1):
Equity securities:
United States large cap	1,183		—		—		1,183
REIT	67		—		—		67
Fixed income:
Corporate debt instruments	—		298		—		298
United States Treasury securities and agency debentures	144		107		—		251
State and municipal	—		174		—		174
Other	—		29		—		29
Total assets	$	1,394	$	636	$	90	$	2,120
Liabilities
Derivatives:
Commodity	$	—	$	22	$	2	$	24
Interest rate	—		267		—		267
Total liabilities	$	—	$	289	$	2	$	291
At December 31, 2015
Assets
Derivatives:
Commodity	$	—	$	13	$	101	$	114
Interest rate	—		13		—		13
Investments(1):
Equity securities:
United States large cap	1,100		—		—		1,100
REIT	63		—		—		63
Fixed income:
Corporate debt instruments	—		238		—		238
United States Treasury securities and agency debentures	180		79		—		259
State and municipal	—		175		—		175
Other	—		34		—		34
Total assets	$	1,343	$	552	$	101	$	1,996
Liabilities
Derivatives:
Commodity	$	—	$	19	$	8	$	27
Interest rate	—		59		—		59
Total liabilities	$	—	$	78	$	8	$	86

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
(millions)
Beginning balance	$	125		$	73		$	93		$	102
Total realized and unrealized gains (losses):
Included in earnings	(7		)	(10		)	(24		)	(1		)
Included in regulatory assets/liabilities	(37		)	47			(5		)	18
Settlements	7			10			24			1
Ending balance	$	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 nine months ended 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 nine months ended September 30, 2016 and 2015.

Dominion Gas

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

	Level 1		Level 2		Level 3		Total
(millions)
At September 30, 2016
Assets
Commodity	$	—	$	6	$	—	$	6
Foreign currency	—		8		—		8
Total Assets	$	—	$	14	$	—	$	14
Liabilities
Commodity	$	—	$	2	$	—	$	2
Foreign currency	—		4		—		4
Total liabilities	$	—	$	6	$	—	$	6
At December 31, 2015
Assets
Commodity	$	—	$	5	$	6	$	11
Total Assets	$	—	$	5	$	6	$	11
Liabilities
Interest rate	$	—	$	14	$	—	$	14
Total liabilities	$	—	$	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 nine months ended 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 nine months ended September 30, 2016 and 2015.

Fair Value of Financial Instruments

Substantially all of the Companies' financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, customer, 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:

	September 30, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	26,287	$	29,077	$	21,873	$	23,210
Junior subordinated notes(3)	2,980		3,030		1,340		1,192
Remarketable subordinated notes(3)	2,371		2,392		2,080		2,129
Virginia Power
Long-term debt, including securities due within one year(3)	$	9,642	$	11,259	$	9,368	$	10,400
Dominion Gas
Long-term debt, including securities due within one year(4)	$	3,945	$	4,139	$	3,269	$	3,299

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2) Carrying amount includes amounts which represent the unamortized debt issuance costs, discount and/or premium, and foreign currency remeasurement adjustments. At September 30, 2016 and December 31, 2015, includes the valuation of certain fair value hedges associated with fixed rate debt of $14 million and $7 million, respectively.

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

(4) Carrying amount includes amounts which represent the unamortized debt issuance costs, discount and/or premium, and foreign currency remeasurement adjustments.

XML

Derivatives and Hedge Accounting Activities

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives and Hedge Accounting Activities

Derivatives and Hedge Accounting Activities

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.

Dominion

Balance Sheet Presentation

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

	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
(millions)
Commodity contracts:
Over-the-counter	$	173	$	—	$	173	$	217	$	—	$	217
Exchange	88		—		88		138		—		138
Interest rate contracts:
Over-the-counter	19		—		19		24		—		24
Foreign currency contracts:
Over-the-counter	8		—		8		—		—		—
Total derivatives, subject to a master netting or similar arrangement	288		—		288		379		—		379
Total derivatives, not subject to a master netting or similar arrangement	7		—		7		9		—		9
Total	$	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

	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
(millions)
Commodity contracts:
Over-the-counter	$	43	$	—	$	43	$	70	$	—	$	70
Exchange	63		—		63		82		—		82
Interest rate contracts:
Over-the-counter	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	$	422	$	—	$	422	$	343	$	—	$	343

			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 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	$	43	$	20	$	—	$	23	$	70	$	37	$	—	$	33
Exchange	63		63		—		—		82		82		—		—
Interest rate contracts:
Over-the-counter	307		10		—		297		183		22		—		161
Foreign currency contracts:
Over-the-counter	4		4		—		—		—		—		—		—
Total	$	417	$	97	$	—	$	320	$	335	$	141	$	—	$	194

Volumes

The following table presents the volume of Dominion’s derivative activity at 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
Natural Gas (bcf):
Fixed price(1)	104		23
Basis	261		626
Electricity (MWh):
Fixed price	8,274,639		659,440
FTRs	72,352,190		—
Liquids (Gal)(2)	39,269,554		—
Interest rate(3)	$	2,200,000,000	$	1,600,000,000
Foreign currency(3)(4)	$	—	$	280,000,000

(1) Includes options.

(2) Includes NGLs and oil.

(3) Maturity is determined based on final settlement period.

(4) Euro equivalent volumes are €250,000,000.

Ineffectiveness and AOCI

For the three and nine months ended 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 September 30, 2016:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(2	)	$	(2	)	39 months
Electricity	44			42			15 months
Other	(1		)	(1		)	6 months
Interest rate	(304		)	(26		)	378 months
Foreign currency	2			—			117 months
Total	$	(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.

Fair Value and Gains and Losses on Derivative Instruments

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

	Fair Value – Derivatives under Hedge  Accounting		Fair Value – Derivatives not under Hedge  Accounting		Total Fair Value
(millions)
At September 30, 2016
ASSETS
Current Assets
Commodity	$	59	$	105	$	164
Interest rate	9		—		9
Total current derivative assets(1)	68		105		173
Noncurrent Assets
Commodity	4		100		104
Interest rate	10		—		10
Foreign currency	8		—		8
Total noncurrent derivative assets(2)	22		100		122
Total derivative assets	$	90	$	205	$	295
LIABILITIES
Current Liabilities
Commodity	$	22	$	78	$	100
Interest rate	182		—		182
Foreign currency	4		—		4
Total current derivative liabilities(3)	208		78		286
Noncurrent Liabilities
Commodity	1		10		11
Interest rate	125		—		125
Total noncurrent derivative liabilities(4)	126		10		136
Total derivative liabilities	$	334	$	88	$	422
At December 31, 2015
ASSETS
Current Assets

Commodity	$	101	$	151	$	252
Interest rate	3		—		3
Total current derivative assets(1)	104		151		255
Noncurrent Assets
Commodity	3		109		112
Interest rate	21		—		21
Total noncurrent derivative assets(2)	24		109		133
Total derivative assets	$	128	$	260	$	388
LIABILITIES
Current Liabilities
Commodity	$	32	$	116	$	148
Interest rate	164		—		164
Total current derivative liabilities(3)	196		116		312
Noncurrent Liabilities
Commodity	—		12		12
Interest rate	19		—		19
Total noncurrent derivative liabilities(4)	19		12		31
Total derivative liabilities	$	215	$	128	$	343

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

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

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

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

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss)  Recognized in AOCI on Derivatives (Effective Portion) (1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended September 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	64
Purchased gas				(1		)
Electric fuel and other energy-related purchases				(1		)
Total commodity	$	7		$	62		$	—
Interest rate(3)	3			(10		)	(16		)
Foreign currency(4)	12			3			—
Total	$	22		$	55		$	(16	)
Three Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	87
Purchased gas				(2		)
Total commodity	$	64		$	85		$	—
Interest rate(3)	(71		)	(2		)	(69		)
Total	$	(7	)	$	83		$	(69	)
Nine Months Ended September 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	266
Purchased gas				(9		)
Electric fuel and other energy-related purchases				(8		)
Total commodity	$	193		$	249		$	—
Interest rate(3)	(107		)	(21		)	(258		)
Foreign currency(4)	4			1			—
Total	$	90		$	229		$	(258	)
Nine Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	103
Purchased gas				(9		)
Total commodity	$	117		$	94		$	3
Interest rate(3)	(72		)	(7		)	(27		)
Total	$	45		$	87		$	(24	)

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

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

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

(4) Amounts recorded in Dominion’s Consolidated Statements of Income are classified in other income.

	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
	Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives Not Designated as Hedging Instruments	2016			2015			2016			2015
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue	$	25		$	2		$	19		$	20
Purchased gas	(21		)	(3		)	(14		)	(12		)
Electric fuel and other energy-related purchases	(12		)	(4		)	(43		)	5
Interest rate(2)	—			(1		)	—			(1		)
Total	$	(8	)	$	(6	)	$	(38	)	$	12

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

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

Virginia Power

Balance Sheet Presentation

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

	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
(millions)
Commodity contracts:
Over-the-counter	$	88	$	—	$	88	$	101	$	—	$	101
Interest rate contracts:
Over-the-counter	2		—		2		13		—		13
Total derivatives, subject to a master netting or similar arrangement	90		—		90		114		—		114
Total derivatives, not subject to a master netting or similar arrangement	28		—		28		13		—		13
Total	$	118	$	—	$	118	$	127	$	—	$	127

			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	$	88	$	2	$	—	$	86	$	101	$	3	$	—	$	98
Interest rate contracts:
Over-the-counter	2		—		—		2		13		10		—		3
Total	$	90	$	2	$	—	$	88	$	114	$	13	$	—	$	101

	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
(millions)
Commodity contracts:
Over-the-counter	$	9	$	—	$	9	$	5	$	—	$	5
Interest rate contracts:
Over-the-counter	267		—		267		59		—		59
Total derivatives, subject to a master netting or similar arrangement	276		—		276		64		—		64
Total derivatives, not subject to a master netting or similar arrangement	15		—		15		22		—		22
Total	$	291	$	—	$	291	$	86	$	—	$	86

			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 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	$	9	$	2	$	—	$	7	$	5	$	3	$	—	$	2
Interest rate contracts:
Over-the-counter	267		—		—		267		59		10		—		49
Total	$	276	$	2	$	—	$	274	$	64	$	13	$	—	$	51

Volumes

The following table presents the volume of Virginia Power’s derivative activity at 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
Natural Gas (bcf):
Fixed price(1)	32		12
Basis	126		558
Electricity (MWh):
FTRs	70,978,901		—
Interest rate	$	1,200,000,000	$	600,000,000

(1) Includes options.

Ineffectiveness and AOCI

For the three and nine months ended 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 September 30, 2016:

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

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 interest rates.

Fair Value and Gains and Losses on Derivative Instruments

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

Balance Sheets:

	Fair Value – Derivatives under Hedge  Accounting		Fair Value – Derivatives not under Hedge  Accounting		Total Fair Value
(millions)
At September 30, 2016
ASSETS
Current Assets
Commodity	$	—	$	25	$	25
Interest rate	2		—		2
Total current derivative assets(1)	2		25		27
Noncurrent Assets
Commodity	—		91		91
Total noncurrent derivative assets(2)	—		91		91
Total derivative assets	$	2	$	116	$	118
LIABILITIES
Current Liabilities
Commodity	$	—	$	19	$	19
Interest rate	142		—		142
Total current derivative liabilities(3)	142		19		161
Noncurrent Liabilities
Commodity	—		5		5
Interest rate	125		—		125
Total noncurrent derivatives liabilities (4)	125		5		130
Total derivative liabilities	$	267	$	24	$	291
At December 31, 2015
ASSETS
Current Assets
Commodity	$	—	$	18	$	18
Total current derivative assets(1)	—		18		18
Noncurrent Assets
Commodity	—		96		96
Interest rate	13		—		13
Total noncurrent derivative assets(2)	13		96		109
Total derivative assets	$	13	$	114	$	127
LIABILITIES
Current Liabilities
Commodity	$	—	$	23	$	23
Interest rate	57		—		57
Total current derivative liabilities(3)	57		23		80
Noncurrent Liabilities
Commodity	—		4		4
Interest rate	2		—		2
Total noncurrent derivative liabilities(4)	2		4		6
Total derivative liabilities	$	59	$	27	$	86

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

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

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

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

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase(Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended September 30, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(2	)	$	—		$	(16	)
Total	$	(2	)	$	—		$	(16	)
Three Months Ended September 30, 2015
Derivative type and location of gains (losses):
Interest rate(3)	$	(9	)	$	—		$	(69	)
Total	$	(9	)	$	—		$	(69	)
Nine Months Ended September 30, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(26	)	$	(1	)	$	(258	)
Total	$	(26	)	$	(1	)	$	(258	)
Nine Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Total commodity	$	—		$	(1	)	$	3
Interest rate(3)	(4		)	—			(27		)
Total	$	(4	)	$	(1	)	$	(24	)

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

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

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

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

(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.

(2) Amounts recorded in Virginia Power's Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.

Dominion Gas

Balance Sheet Presentation

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

	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
(millions)
Commodity contracts:
Over-the-counter	$	6	$	—	$	6	$	11	$	—	$	11
Foreign currency contracts:
Over-the-counter	8		—		8		—		—		—
Total derivatives, subject to a master netting or similar arrangement	$	14	$	—	$	14	$	11	$	—	$	11

			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	$	6	$	1	$	—	$	5	$	11	$	—	$	—	$	11
Foreign currency contracts:
Over-the-counter	8		4		—		4		—		—		—		—
Total	$	14	$	5	$	—	$	9	$	11	$	—	$	—	$	11

	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
(millions)
Commodity contracts:
Over-the-counter	$	2	$	—	$	2	$	—	$	—	$	—
Interest rate contracts:
Over-the-counter	—		—		—		14		—		14
Foreign currency contracts:
Over-the-counter	4		—		4		—		—		—
Total derivatives, subject to a master netting or similar arrangement	$	6	$	—	$	6	$	14	$	—	$	14

			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 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	$	2	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Interest rate contracts:
Over-the-counter	—		—		—		—		14		—		—		14
Foreign currency contracts:
Over-the-counter	4		4		—		—		—		—		—		—
Total	$	6	$	5	$	—	$	1	$	14	$	—	$	—	$	14

Volumes

The following table presents the volume of Dominion Gas' derivative activity at 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
Natural Gas (bcf):
Fixed price	6		—
Basis	6		—
NGLs (Gal)	33,095,554		—
Foreign currency(1)	$	—	$	280,000,000

(1) Maturity is determined based on final settlement period. Euro equivalent volumes are €250,000,000.

Ineffectiveness and AOCI

For the three and nine months ended 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 September 30, 2016:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
NGLs	$	(1	)	$	(1	)	6 months
Interest rate	(27		)	(2		)	339 months
Foreign currency	2			—			117 months
Total	$	(26	)	$	(3	)

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 rates.

Fair Value and Gains and Losses on Derivative Instruments

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
(millions)
At September 30, 2016
ASSETS
Current Assets
Commodity	$	1	$	5	$	6
Total current derivative assets(1)	1		5		6
Noncurrent Assets
Foreign currency	8		—		8
Total noncurrent derivative assets(2)	8		—		8
Total derivative assets	$	9	$	5	$	14
LIABILITIES
Current Liabilities
Commodity	$	2	$	—	$	2
Foreign currency	4		—		4
Total current derivative liabilities(3)	6		—		6
Total derivative liabilities	$	6	$	—	$	6
At December 31, 2015
ASSETS
Current Assets
Commodity	$	10	$	—	$	10
Total current derivative assets(1)	10		—		10
Noncurrent Assets
Commodity	1		—		1
Total noncurrent derivatives assets(2)	1		—		1
Total derivative assets	$	11	$	—	$	11
LIABILITIES
Noncurrent Liabilities
Interest rate	$	14	$	—	$	14
Total noncurrent derivative liabilities(4)	14		—		14
Total derivative liabilities	$	14	$	—	$	14

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

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

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

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

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income
(millions)
Three Months Ended September 30, 2016
Derivative Type and Location of Gains (Losses):
Commodity:
Operating revenue				$	1
Total commodity	$	—		$	1
Interest rate(2)	—			(1		)
Foreign currency(3)	12			3
Total	$	12		$	3
Three Months Ended September 30, 2015
Derivative Type and Location of Gains (Losses):
Commodity:
Operating revenue				$	3
Total commodity	$	11		$	3
Interest rate(2)	(7		)	—
Total	$	4		$	3
Nine Months Ended September 30, 2016
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	6
Total commodity	$	(7	)	$	6
Interest rate(2)	(8		)	(2		)
Foreign currency(3)	4			1
Total	$	(11	)	$	5
Nine Months Ended September 30, 2015
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	4
Total commodity	$	10		$	4
Interest rate(2)	(8		)	—
Total	$	2		$	4

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

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

(3) Amounts recorded in Dominion Gas' Consolidated Statements of Income are classified in other income.

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

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Investments

9 Months Ended

Sep. 30, 2016

Investments, Debt and Equity Securities [Abstract]

Investments

Investments

Dominion

Equity and Debt Securities

Rabbi Trust Securities

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

Decommissioning Trust Securities

Dominion holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below:

	Amortized Cost		Total  Unrealized Gains(1)		Total  Unrealized Losses(1)				Fair Value
(millions)
At September 30, 2016
Marketable equity securities:
United States large cap	$	1,361	$	1,312	$	—			$	2,673
REIT	59		8		—				67
Marketable debt securities:
Corporate bonds	493		26		(1		)		518
United States Treasury securities and agency debentures	645		21		—				666
State and municipal	306		27		—				333
Other	89		—		—				89
Cost method investments	69		—		—				69
Cash equivalents and other(2)	12		—		—				12
Total	$	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
REIT	59		4		—				63
Marketable debt securities:
Corporate bonds	433		11		(7		)		437
United States Treasury securities and agency debentures	654		8		(4		)		658
State and municipal	312		22		—				334
Other	99		—		—				99
Cost method investments	70		—		—				70
Cash equivalents and other(2)	14		—		—				14
Total	$	2,936	$	1,258	$	(11	)	(3)	$	4,183

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

(2) Includes pending sales of securities of $9 million and $12 million at September 30, 2016 and December 31, 2015, respectively.

(3) The fair value of securities in an unrealized loss position was $156 million and $592 million at September 30, 2016 and December 31, 2015, respectively.

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at 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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Proceeds from sales	$	300	$	357	$	1,009	$	937
Realized gains(1)	40		65		102		165
Realized losses(1)	9		40		43		69

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

Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
(millions)
Total other-than-temporary impairment losses(1)	$	9		$	29		$	34		$	55
Losses recorded to the nuclear decommissioning trust regulatory liability	(4		)	(10		)	(15		)	(21		)
Losses recognized in other comprehensive income (before taxes)	—			(3		)	(1		)	(7		)
Net impairment losses recognized in earnings	$	5		$	16		$	18		$	27

(1) Amounts include other-than-temporary impairment losses for debt securities of less than $1 million and $3 million for the three months ended September 30, 2016 and 2015, respectively, and $2 million and $7 million for the nine months ended September 30, 2016 and 2015, respectively.

Virginia Power

Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below:

	Amortized Cost		Total  Unrealized Gains(1)		Total  Unrealized Losses(1)				Fair Value
(millions)
At September 30, 2016
Marketable equity securities:
United States large cap	$	606	$	576	$	—			$	1,182
REIT	59		8		—				67
Marketable debt securities:
Corporate bonds	285		13		—				298
United States Treasury securities and agency debentures	246		5		—				251
State and municipal	158		15		—				173
Other	29		—		—				29
Cost method investments	69		—		—				69
Cash equivalents and other(2)	5		—		—				5
Total	$	1,457	$	617	$	—		(3)	$	2,074
At December 31, 2015
Marketable equity securities:
United States large cap	$	574	$	525	$	—			$	1,099
REIT	59		4		—				63
Marketable debt securities:
Corporate bonds	237		5		(4		)		238
United States Treasury securities and agency debentures	260		1		(2		)		259
State and municipal	162		13		(1		)		174
Other	34		—		—				34
Cost method investments	70		—		—				70
Cash equivalents and other(2)	8		—		—				8
Total	$	1,404	$	548	$	(7	)	(3)	$	1,945

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

(2) Includes pending sales of securities of $4 million and $8 million at September 30, 2016 and December 31, 2015, respectively.

(3) The fair value of securities in an unrealized loss position was $91 million and $281 million at September 30, 2016 and December 31, 2015, respectively.

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

	Amount
(millions)
Due in one year or less	$	51
Due after one year through five years	228
Due after five years through ten years	202
Due after ten years	270
Total	$	751

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Proceeds from sales	$	131	$	198	$	478	$	407
Realized gains(1)	18		45		48		82
Realized losses(1)	4		18		21		33

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

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

Equity Method Investments

Dominion

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

Iroquois

Dominion Gas' equity earnings totaled $14 million and $17 million for the nine months ended September 30, 2016 and 2015, respectively. Dominion Gas received distributions from this investment of $17 million and $26 million for the nine months ended September 30, 2016 and 2015, respectively. At September 30, 2016 and December 31, 2015, the carrying amount of Dominion Gas' investment of $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, included in other income in Dominion Gas’ Consolidated Statements of Income.

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Regulatory Assets and Liabilities

9 Months Ended

Sep. 30, 2016

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

Regulatory assets and liabilities include the following:

	September 30, 2016		December 31, 2015
(millions)
Dominion
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	101	$	90
Deferred nuclear refueling outage costs(2)	60		75
Deferred cost of fuel used in electric generation(3)	3		111
Other	86		75
Regulatory assets-current(4)	250		351
Unrecognized pension and other postretirement benefit costs(5)	981		1,015
Derivatives(6)	366		110
Deferred rate adjustment clause costs(1)	271		295
PJM transmission rates(7)	192		192
Income taxes recoverable through future rates(8)	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
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)	21		20
Other	82		65
Regulatory assets-non-current(13)	469		449
Total regulatory assets	$	491	$	472
Regulatory liabilities:
PIPP(9)	$	26	$	46
Other	13		9

Regulatory liabilities-current(10)	39		55
Provision for future cost of removal and AROs(11)	173		170
Other	44		31
Regulatory liabilities-non-current(14)	217		201
Total regulatory liabilities	$	256	$	256

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

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

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Regulatory Matters

9 Months Ended

Sep. 30, 2016

Regulated Operations [Abstract]

Regulatory Matters

Regulatory Matters

Regulatory Matters Involving Potential Loss Contingencies

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

FERC - Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Dominion’s merchant generators sell electricity in the 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.

Rates

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

In March 2010, 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.

PJM Transmission Rates

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

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015 and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016 and June 30, 2016.

Virginia Regulation

Virginia Fuel Expenses

In May 2016, Virginia Power submitted its annual fuel factor to the Virginia Commission to recover an estimated $1.4 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 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. In October 2016, the Virginia Commission approved Virginia Power's proposed fuel rate. 

Rate Adjustment Clauses

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

• The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In October 2016, Virginia Power proposed a $134 million revenue requirement for the rate year beginning September 1, 2017, which represents a $14 million increase over the previous year. This case is pending.

• The Virginia Commission previously approved Rider US-2 in conjunction with the Scott Solar, Whitehouse, and Woodland solar facilities. In October 2016, Virginia Power proposed a $10 million revenue requirement for the rate year beginning September 1, 2017, which represents a $6 million increase over the previous year. This case is pending.

• The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2016, Virginia Power proposed a total revenue requirement of $45 million for the rate year beginning July 1, 2017. Virginia Power also proposed two new energy efficiency programs for Virginia Commission approval with a requested five-year cost cap of $178 million for those programs. Virginia Power further proposed to extend an existing energy efficiency program for an additional two years under current funding, and an existing peak shaving program for an additional five years with an additional $5 million cost cap. This case is pending.

• Virginia Power previously filed for Virginia Commission approval of a revised Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by prior Virginia legislation. In August 2016, the Virginia Commission approved a net $20 million revenue requirement and a 9.6% ROE for the rate year beginning September 1, 2016, and an additional $2 million in credits for each of the 2017-2018 and 2018-2019 rate years. The order limited the total investment in Phase One of Virginia Power’s proposed program to $140 million, with $123 million recoverable through Rider U.

Electric Transmission Project

Virginia Power previously filed an application with the Virginia Commission for a CPCN to construct and operate in Loudoun County, Virginia, a new approximately 230 kV Poland Road substation, and a new approximately four mile overhead 230 kV double circuit transmission line between the existing 230 kV Loudoun-Brambleton line and the Poland Road substation. In August 2016, the Virginia Commission granted a CPCN to construct and operate the project along a revised route.

North Anna

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.

Requests by BREDL for a contested NRC hearing on Virginia Power’s COL application have been dismissed, and in September 2016, the United States Court of Appeals for the District of Columbia dismissed with prejudice petitions for judicial review that BREDL and other organizations had filed challenging the NRC’s reliance on a rule generically assessing the environmental impacts of continued onsite storage of spent nuclear fuel in various licensing proceedings, including Virginia Power’s COL proceeding. This dismissal followed the Court’s June 2016 decision in New York v. NRC, upholding the NRC’s continued storage rule and August 2016 denial of requests for rehearing en 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.

North Carolina Regulation

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 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 North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $36 million decrease to the fuel component of its electric rates for the rate year beginning January 1, 2017. This case is pending.

Ohio Regulation

PIR

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In 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 annual capital expenditures to $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.

PSMP

In November 2016, the Ohio Commission approved East Ohio’s request to defer the operation and maintenance costs associated with implementing PSMP of up to $15 million per year.

West Virginia Regulation

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. In September 2016, Hope reached a settlement with all parties to the case agreeing to new PREP customer rates, for the year beginning November 1, 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.

FERC - Gas

In August 2016, Dominion Gas received FERC authorization to construct and operate the Leidy South Project facilities. Service under the 20-year contracts is expected to commence in the fourth quarter of 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.

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Variable Interest Entities

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Variable Interest Entities

Variable Interest Entities

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

Dominion

As of September 30, 2016, Dominion owns the general partner interest and 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 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

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 and Dominion Gas

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

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 $320 million as of September 30, 2016. Virginia Power paid $37 million and $52 million for electric capacity and $11 million and $17 million for electric energy to these entities in the three months ended 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.

Dominion Gas

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

Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of $80 million and $31 million for the three months ended September 30, 2016, $73 million and $27 million for the three months ended September 30, 2015, $268 million and $95 million for the nine months ended September 30, 2016 and $239 million and $85 million for the nine months ended 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.

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Significant Financing Transactions

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Significant Financing Transactions

Significant Financing Transactions

Credit Facilities and Short-term Debt

The Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties.

Dominion

At 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
(millions)
Joint revolving credit facility(1)	$	5,000	$	3,073	$	—	$	1,927
Joint revolving credit facility(1)	500		—		60		440
Revolving multi-year credit facility(2)	500		24		—		476
Revolving 364-day credit facility(2)	250		—		—		250
Total	$	6,250	$	3,097	$	60	$	3,093

(1) In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

(2) These Dominion Questar facilities were terminated in October 2016.

Virginia Power

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 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
(millions)
Joint revolving credit facility(1)	$	5,000	$	965	$	—
Joint revolving credit facility(1)	500		—		—
Total	$	5,500	$	965	$	—

(1) The full amount of the facilities is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion and Dominion Gas. Sub-limits for Virginia Power are set within the facility limit but can be changed at the option of the Companies multiple times per year. At September 30, 2016, the aggregate sub-limit for Virginia Power was $2.0 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion. In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

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 September 30, 2016, this facility supports $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

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 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
(millions)
Joint revolving credit facility(1)	$	1,000	$	60	$	—
Joint revolving credit facility(1)	500		—		—
Total	$	1,500	$	60	$	—

(1) A maximum of a combined $1.5 billion of the facilities is available to Dominion Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion and Virginia Power. Sub-limits for Dominion Gas are set within the facility limit but can be changed at the option of the Companies multiple times per year. In September 2016, the aggregate sub-limit for Dominion Gas was decreased from $1.0 billion to $750 million. If Dominion Gas has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion. In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

Remarketable Subordinated Notes

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 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.

Selected information about Dominion’s 2016 Equity Units is presented below:

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

(1) Annual interest rate applies to each of the Series A-1 RSNs and Series A-2 RSNs.

(2) The maturity dates of the $700 million Series A-1 RSNs and $700 million Series A-2 RSNs are August 15, 2021 and August 15, 2024, respectively.

Enhanced Junior Subordinated Notes

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 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.

Long-term Debt

In May 2016, Dominion Gas issued $150 million of private placement 3.8% senior notes that mature in 2031. In June 2016, Dominion Gas issued $250 million of private placement 2.875% senior notes that mature in 2023. Also in June 2016, Dominion Gas issued €250 million of private placement 1.45% 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 $281 million at 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.

Short-term Notes

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.

Issuance of Common Stock

Dominion maintains Dominion Direct® and a number of employee savings plans through which contributions may be invested in Dominion’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans.

In 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 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 received proceeds of $756 million through a registered underwritten public offering. A portion of the net proceeds was used to finance the Dominion Questar Combination. See Note 3 for more information.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

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

Environmental Matters

The Companies are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

Air

CAA

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.

MATS

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. 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 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.

CAIR

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.

CSAPR

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) 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.

Ozone Standards

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. 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.

NO_x and VOC Emissions

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.

NSPS

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 and Dominion Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.

Methane Emissions

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 founding partners in this program for its distribution companies, East Ohio and Hope, DTI and 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 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.

Climate Change Legislation and Regulation

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 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. In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to 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 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 final action on this rulemaking, the Companies cannot predict the impact to their financial 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.

Water

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

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion and Virginia Power have14 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.

Solid and Hazardous Waste

The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the 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. The Companies do not believe 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. In September 2016, the United States, on behalf of the EPA, lodged a 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 between the EPA and a number of parties, including Virginia Power. The Consent Decree identifies Virginia Power as a non-performing cash-out party to the settlement and, once approved by the court, would resolve Virginia Power’s alleged liability under CERCLA with respect to the site, including liability pursuant to the UAO. The ultimate outcome of this matter depends on the approval of the Consent Decree by the Court, and cannot be predicted at this time; however, this matter is not expected to have a material effect on Virginia Power.

Dominion has determined that it is associated with 19 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion Gas. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which the Companies are associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.

See below for discussion on ash pond and landfill closure costs.

Other Legal Matters

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

Appalachian Gateway

Pipeline Contractor Litigation

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.

Gas Producers Litigation

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.

Ash Pond and Landfill Closure Costs

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 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. In November 2016, the court dismissed the remaining appeal. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the increased obligation in 2015.

Cove Point

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 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.

FERC

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.

Greensville County

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.

Nuclear Matters

In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as 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.

Guarantees, Surety Bonds and Letters of Credit

Dominion

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

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	27	$	27
Commodity transactions(3)	2,081		874
Nuclear obligations(4)	169		94
Cove Point(5)	1,900		—
Solar(6)	1,847		539
Other(7)	783		60
Total	$	6,807	$	1,594

(1) Represents the estimated portion of the guarantee's stated limit that is utilized as of September 30, 2016 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

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

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

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

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

(6) Includes guarantees related to solar projects including guarantees that do not have stated limits. Also includes guarantees related to solar projects entered into by DEI on behalf of certain subsidiaries. 

(7) Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries' obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of September 30, 2016, Dominion's maximum remaining cumulative exposure under these equity funding agreements is $36 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits.

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

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Credit Risk

9 Months Ended

Sep. 30, 2016

Risks and Uncertainties [Abstract]

Credit Risk

Credit Risk

The Companies' accounting policies for credit risk are discussed in Note 23 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 2015.

At September 30, 2016, Dominion's credit exposure related to energy marketing and price risk management activities totaled $96 million. Of this amount, investment grade counterparties, including those internally rated, represented 70%. No single counterparty, whether investment grade or non-investment grade, exceeded $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.

Credit-Related Contingent Provisions

The majority of Dominion's derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of September 30, 2016 and December 31, 2015, Dominion would have been required to post an additional $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 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 September 30, 2016 and December 31, 2015 was $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 September 30, 2016 and December 31, 2015. See Note 9 for further information about derivative instruments.

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Related-Party Transactions

9 Months Ended

Sep. 30, 2016

Related Party Transactions [Abstract]

Related-Party Transactions

Related-Party Transactions

Virginia Power and Dominion Gas engage in related-party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power's and Dominion Gas' receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power and Dominion Gas are included in Dominion's consolidated federal income tax return. Dominion's transactions with equity method investments are described in Note 10. A discussion of significant related-party transactions follows.

Virginia Power

Transactions with Affiliates

Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity physical forwards and options, to manage commodity price risks associated with purchases of natural gas. As of September 30, 2016, Virginia Power’s derivative assets and liabilities with affiliates were $28 million and $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 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 $376 million and $316 million, respectively, and amounts due from Dominion at September 30, 2016 and December 31, 2015 included in other deferred charges and other assets were $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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Commodity purchases from affiliates	$	172	$	123	$	416	$	469
Services provided by affiliates(1)	105		96		347		313
Services provided to affiliates	5		5		17		15

(1) Includes capitalized expenditures of $32 million for both the three months ended September 30, 2016 and 2015, and $109 million and $105 million for the nine months ended September 30, 2016 and 2015, respectively.

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 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 September 30, 2016 and December 31, 2015. Interest charges related to Virginia Power's borrowings from Dominion were immaterial for the three and nine months ended September 30, 2016 and 2015.

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

Dominion Gas

Transactions with Related Parties

Dominion Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Gas provides transportation and storage services to affiliates. Dominion Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of 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 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 $686 million and $652 million, respectively, and amounts due to Dominion at 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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Purchases of natural gas and transportation and storage services from affiliates	$	2	$	3	$	7	$	7
Sales of natural gas and transportation and storage services to affiliates	16		17		51		52
Services provided by related parties(1)	36		30		108		99
Services provided to related parties (2)	34		30		94		75

(1) Includes capitalized expenditures of $13 million and $16 million for the three months ended September 30, 2016 and 2015, respectively, and $37 million and $40 million for the nine months ended September 30, 2016 and 2015, respectively.

(2) Amounts primarily attributable to Atlantic Coast Pipeline.

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

	September 30, 2016		December 31, 2015
(millions)
Other receivables(1)	$	9	$	7
Customer receivables from related parties	1		4
Imbalances receivable from affiliates(2)	1		1
Affiliated notes receivable(3)	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 September 30, 2016 and December 31, 2015, respectively. Interest charges related to Dominion Gas' total borrowings from Dominion were immaterial for the three and nine months ended September 30, 2016 and 2015.

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Employee Benefit Plans

9 Months Ended

Sep. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

Employee Benefit Plans

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 nine months ended 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.

Dominion

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

	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016			2015
(millions)
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	$	87		$	95		$	23		$	30
Interest cost	234			215			50			50
Expected return on plan assets	(419		)	(398		)	(87		)	(88		)
Amortization of prior service cost (credit)	1			1			(23		)	(20		)
Amortization of net actuarial loss	84			120			5			4
Net periodic benefit cost (credit)	$	(13	)	$	33		$	(32	)	$	(24	)

Plan Amendment and Remeasurement

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.

Employer Contributions

During the nine months ended 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

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
	2016			2015			2016			2015
(millions)
Three Months Ended September 30,
Service cost	$	3		$	4		$	1		$	2
Interest cost	7			7			3			3
Expected return on plan assets	(33		)	(31		)	(5		)	(6		)
Amortization of net actuarial loss	3			5			—			1
Net periodic benefit credit	$	(20	)	$	(15	)	$	(1	)	$	—
Nine Months Ended September 30,
Service cost	$	10		$	11		$	4		$	5
Interest cost	22			21			10			10
Expected return on plan assets	(100		)	(94		)	(17		)	(18		)
Amortization of net actuarial loss	10			15			1			2
Net periodic benefit credit	$	(58	)	$	(47	)	$	(2	)	$	(1	)

Employer Contributions

During the nine months ended 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.

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Operating Segments

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Operating Segments

Operating Segments

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:

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

(1) Includes remaining producer services activities for Dominion.

(2) As a result of Dominion's decision to realign its business units effective for 2015 year-end reporting, nonregulated retail energy marketing operations were moved from the Dominion Generation segment to the Dominion Energy segment.

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

Dominion

The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of operations that are discontinued or sold. In addition, Corporate and Other includes specific items attributable to Dominion's operating segments that are not included in profit measures evaluated by executive management in assessing the segments' performance or in allocating resources.

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

• A $59 million ($36 million after-tax) charge related to an organizational design initiative, attributable to:

• DVP ($5 million after-tax);

• Dominion Energy ($12 million after-tax); and

• Dominion Generation ($19 million after-tax); partially offset by

• A $29 million ($18 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.

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:

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

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

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

• A $39 million ($25 million after-tax) net gain on investments held in nuclear decommissioning trust funds.

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
(millions)
Three Months Ended September 30, 2016
Total revenue from external customers	$	614	$	1,947	$	359	$	2		$	210		$	3,132
Intersegment revenue	6		2		205		144			(357		)	—
Total operating revenue	620		1,949		564		146			(147		)	3,132
Net income (loss) attributable to Dominion	139		650		135		(234		)	—			690
Three Months Ended September 30, 2015
Total revenue from external customers	$	539	$	1,892	$	377	$	—		$	163		$	2,971
Intersegment revenue	4		2		159		128			(293		)	—
Total operating revenue	543		1,894		536		128			(130		)	2,971
Net income (loss) attributable to Dominion	125		390		153		(75		)	—			593
Nine Months Ended September 30, 2016
Total revenue from external customers	$	1,682	$	5,204	$	1,235	$	8		$	522		$	8,651
Intersegment revenue	17		7		507		469			(1,000		)	—
Total operating revenue	1,699		5,211		1,742		477			(478		)	8,651
Net income (loss) attributable to Dominion	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

(1) 2015 amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Energy segment.

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

Virginia Power

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

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

• A $33 million ($20 million after-tax) charge related to an organizational design initiative, attributable to:

• DVP ($5 million after-tax); and

• Dominion Generation ($15 million after-tax).

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:

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

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

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

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

	DVP		Dominion Generation		Corporate and Other			Consolidated Total
(millions)
Three Months Ended September 30, 2016
Operating revenue	$	617	$	1,594	$	—		$	2,211
Net income	140		359		4			503
Three Months Ended September 30, 2015
Operating revenue	$	541	$	1,523	$	(6	)	$	2,058
Net income (loss)	125		273		(13		)	385
Nine Months Ended September 30, 2016
Operating revenue	$	1,686	$	4,191	$	—		$	5,877
Net income (loss)	362		699		(15		)	1,046
Nine Months Ended September 30, 2015
Operating revenue	$	1,610	$	4,419	$	(21	)	$	6,008
Net income (loss)	382		618		(100		)	900

Dominion Gas

The Corporate and Other Segment of Dominion Gas primarily includes specific items attributable to Dominion Gas' operating segment that are not included in profit measures evaluated by executive management in assessing the segment's performance 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 nine months ended September 30, 2016, Dominion Gas reported an after-tax net benefit of $5 million for specific items in the Corporate and Other segment, with after-tax net expense of $7 million attributable to its operating segment. In the nine months ended 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
(millions)
Three Months Ended September 30, 2016
Operating revenue	$	382	$	—		$	382
Net income	77		6			83
Three Months Ended September 30, 2015
Operating revenue	$	365	$	—		$	365
Net income (loss)	113		(2		)	111
Nine Months Ended September 30, 2016
Operating revenue	$	1,181	$	—		$	1,181
Net income (loss)	288		(2		)	286
Nine Months Ended September 30, 2015
Operating revenue	$	1,291	$	—		$	1,291
Net income (loss)	364		(7		)	357

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Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Basis of Accounting

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.

Estimates

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.

Consolidation

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.

Consolidation, consolidated entities and noncontrolling interest

For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. As of September 30, 2016, Dominion owns the general partner and 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 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.

Reclassifications

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.

Fair Value Measurements

The Companies' fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 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:

• Foreign currency forward exchange rates

• Credit quality of counterparties and the Companies

• Notional value

• Credit enhancements

• Time value

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. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices, and volumes. For Level 3 fair value measurements, forward market prices, and implied price volatilities are considered unobservable. The unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.

Derivatives and Hedge Accounting Activities

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.

Regulatory Matters Involving Potential Loss Contingencies

Regulatory Matters Involving Potential Loss Contingencies

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

Commitments and Contingencies

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

Guarantees, Surety Bonds and Letters of Credit

Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion's consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries' obligations.

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Acquisitions and Dispositions (Tables)

9 Months Ended

Sep. 30, 2016

Business Acquisition [Line Items]

Schedule of Business Acquisitions

The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion in the 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	Initial Acquisition Cost (millions)(1)		Project Cost (millions)(2)		Date of Commercial Operations	MW Capacity
April 2015	EC&R NA Solar PV, LLC	1	California	Alamo	$	66	$	66	May 2015	20
April 2015	EDF Renewable Development, Inc.	3	California	Cottonwood(3)	106		106		May 2015	24
June 2015	EDF Renewable Development, Inc.	1	California	Catalina 2	68		68		July 2015	18
July 2015	SunPeak Solar, LLC	1	California	Imperial Valley 2	42		71		August 2015	20

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

(2) Includes acquisition cost.

(3) One of the projects, Marin Carport, began commercial operations in 2016.

Dominion Questar Corporation

Business Acquisition [Line Items]

Schedule of Business Acquisitions

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 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

(1) Includes $40 million for an equity method investment in White River Hub. The fair value adjustment on the equity method investment in White River Hub is considered to be equity method goodwill and is not amortized.

(2) Nonregulated property, plant and equipment, excluding land, will be depreciated over remaining useful lives primarily ranging from 9 to 18 years.

(3) Includes $301 million of short-term debt, of which $24 million is outstanding at September 30, 2016, as well as a $250 million short-term note which matures in February 2017 and bears interest at a variable rate.

(4) Unsecured senior notes have maturities which range from 2017 to 2048 and bear interest at rates from 2.98% to 7.20%.

(5) Includes a $35 million capital lease obligation with undiscounted future minimum lease payments of $1 million remaining in 2016, $4 million per year for 2017 through 2020, and $37 million in total thereafter.

Business Acquisition, Pro Forma Information

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.

	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

(1) Amounts include adjustments for non-recurring costs directly related to the Dominion Questar Combination.

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Operating Revenue (Tables)

9 Months Ended

Sep. 30, 2016

Regulated and Unregulated Operating Revenue [Abstract]

Operating Revenue

The Companies’ operating revenue consists of the following:

	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

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Effective Income Tax

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
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	%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.7		4.0		3.9		4.2		0.8		4.1
Investment tax credits	(10.4	)	(3.5	)	—		—		—		—
Production tax credits	(0.8	)	(0.8	)	(0.5	)	(0.5	)	—		—
State legislative change	(0.8	)	(0.2	)	—		—		—		—
Other, net	(2.1	)	(0.7	)	(0.5	)	(0.2	)	0.4		0.4
Effective tax rate	24.6	%	33.8	%	37.9	%	38.5	%	36.2	%	39.5	%

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Earnings Per Share Computation

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions, except EPS)
Net income attributable to Dominion	$	690	$	593	$	1,666	$	1,542
Average shares of common stock outstanding – Basic	625.9		594.6		612.8		591.3
Net effect of dilutive securities(1)	0.1		0.9		1.0		1.4
Average shares of common stock outstanding – Diluted	626.0		595.5		613.8		592.7
Earnings Per Common Share – Basic	$	1.10	$	1.00	$	2.72	$	2.61
Earnings Per Common Share – Diluted	$	1.10	$	1.00	$	2.71	$	2.60

(1) Dilutive securities consist primarily of the 2013 Equity Units for the nine months ended September 30, 2016 and the three and nine months ended September 30, 2015. See Note 14 in this report and Note 17 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 2015 for more information.

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Accumulated Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2016

Accumulated Other Comprehensive Income (Loss) [Line Items]

Schedule of Accumulated Other Comprehensive Income (Loss)

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

	Deferred Gains and Losses on Derivatives-Hedging Activities			Unrealized Gains and Losses on Investment Securities			Unrecognized Pension and Other Postretirement Benefit Costs			Other Comprehensive Income (Loss) From Equity Method Investee			Total
(millions)
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	$	(146	)	$	519		$	(754	)	$	(5	)	$	(386	)
Other comprehensive income before reclassifications: gains (losses)	(7		)	(59		)	(9		)	1			(74		)
Amounts reclassified from AOCI(1): (gains) losses	(53		)	(2		)	14			—			(41		)
Net current-period other comprehensive income (loss)	(60		)	(61		)	5			1			(115		)
Ending balance	$	(206	)	$	458		$	(749	)	$	(4	)	$	(501	)
Nine Months Ended September 30, 2016
Beginning balance	$	(176	)	$	504		$	(797	)	$	(5	)	$	(474	)
Other comprehensive income before reclassifications: gains (losses)	56			72			15			(1		)	142
Amounts reclassified from AOCI(1): (gains) losses	(141		)	(23		)	25			—			(139		)
Net current-period other comprehensive income (loss)	(85		)	49			40			(1		)	3
Ending balance	$	(261	)	$	553		$	(757	)	$	(6	)	$	(471	)
Nine Months Ended September 30, 2015
Beginning balance	$	(178	)	$	548		$	(782	)	$	(4	)	$	(416	)
Other comprehensive income before reclassifications: gains (losses)	25			(55		)	(6		)	—			(36		)
Amounts reclassified from AOCI(1): (gains) losses	(53		)	(35		)	39			—			(49		)
Net current-period other comprehensive income (loss)	(28		)	(90		)	33			—			(85		)
Ending balance	$	(206	)	$	458		$	(749	)	$	(4	)	$	(501	)

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

Reclassification out of Accumulated Other Comprehensive Income

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

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

Tax	21			Income tax expense
	$	(34	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(25	)	Other income
Impairment	5			Other income
	(20		)
Tax	7			Income tax expense
	$	(13	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(4	)	Other operations and maintenance
Actuarial (gains) losses	17			Other operations and maintenance
	13
Tax	(4		)	Income tax expense
	$	9
Three Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(87	)	Operating revenue
	2			Purchased gas
Interest rate contracts	2			Interest and related charges
	(83		)
Tax	30			Income tax expense
	$	(53	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(18	)	Other income
Impairment	16			Other income
	(2		)
Tax	—			Income tax expense
	$	(2	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(3	)	Other operations and maintenance
Actuarial (gains) losses	24			Other operations and maintenance
	21
Tax	(7		)	Income tax expense
	$	14
Nine Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(266	)	Operating revenue
	9			Purchased gas
	8			Electric fuel and other energy-related purchases
Interest rate contracts	21			Interest and related charges
Foreign currency contracts	(1		)	Other income
	(229		)
Tax	88			Income tax expense
	$	(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	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(11	)	Other operations and maintenance
Actuarial (gains) losses	52			Other operations and maintenance
	41
Tax	(16		)	Income tax expense
	$	25
Nine Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(103	)	Operating revenue
	9			Purchased gas
Interest rate contracts	7			Interest and related charges
	(87		)
Tax	34			Income tax expense
	$	(53	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(82	)	Other income
Impairment	27			Other income
	(55		)
Tax	20			Income tax expense
	$	(35	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(9	)	Other operations and maintenance
Actuarial (gains) losses	73			Other operations and maintenance
	64
Tax	(25		)	Income tax expense
	$	39

Dominion Gas Holdings, LLC

Accumulated Other Comprehensive Income (Loss) [Line Items]

Schedule of Accumulated Other Comprehensive Income (Loss)

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

	Deferred Gains and Losses on Derivatives-Hedging Activities			Unrecognized Pension and Other Postretirement Benefit Costs			Total
(millions)
Three Months Ended September 30, 2016
Beginning balance	$	(34	)	$	(81	)	$	(115	)
Other comprehensive income before reclassifications: gains	9			—			9
Amounts reclassified from AOCI(1): (gains) losses	(1		)	1			—
Net current-period other comprehensive income	8			1			9
Ending balance	$	(26	)	$	(80	)	$	(106	)
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	)
Other comprehensive income before reclassifications: losses	(6		)	—			(6		)
Amounts reclassified from AOCI(1): (gains) losses	(3		)	2			(1		)
Net current-period other comprehensive income (loss)	(9		)	2			(7		)
Ending balance	$	(26	)	$	(80	)	$	(106	)
Nine Months Ended September 30, 2015
Beginning balance	$	(20	)	$	(66	)	$	(86	)
Other comprehensive income before reclassifications: gains	2			—			2
Amounts reclassified from AOCI(1): (gains) losses	(3		)	3			—
Net current-period other comprehensive income (loss)	(1		)	3			2
Ending balance	$	(21	)	$	(63	)	$	(84	)

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

Reclassification out of Accumulated Other Comprehensive Income

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

Details About AOCI Components	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Three Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(1	)	Operating revenue
Interest rate contracts	1			Interest and related charges
Foreign currency contracts	(3		)	Other income
	(3		)
Tax	2			Income tax expense
	$	(1	)
Unrecognized pension and other postretirement benefit costs:

Actuarial (gains) losses	$	2		Other operations and maintenance
	2
Tax	(1		)	Income tax expense
	$	1
Three Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(3	)	Operating revenue
	(3		)
Tax	1			Income tax expense
	$	(2	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	2		Other operations and maintenance
	2
Tax	(1		)	Income tax expense
	$	1
Nine Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(6	)	Operating revenue
Interest rate contracts	2			Interest and related charges
Foreign currency contracts	(1		)	Other income
	(5		)
Tax	2			Income tax expense
	$	(3	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	4		Other operations and maintenance
	4
Tax	(2		)	Income tax expense
	$	2
Nine Months Ended September 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(4	)	Operating revenue
	(4		)
Tax	1			Income tax expense
	$	(3	)
Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	6		Other operations and maintenance
	6
Tax	(3		)	Income tax expense
	$	3

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2016

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value Inputs, Assets, Quantitative Information

The following table presents Dominion's quantitative information about Level 3 fair value measurements at September 30, 2016. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)	$	85	Discounted cash flow	Market price (per Dth)	(3)	(2) - 7	—
FTRs	7		Discounted cash flow	Market price (per MWh)	(3)	(6) - 6	1
Physical and financial options:
Natural gas	4		Option model	Market price (per Dth)	(3)	2 - 7	3
				Price volatility	(4)	19% - 46%	24	%
Total assets	$	96
Liabilities
Physical and financial forwards and futures:
Natural gas(2)	$	4	Discounted cash flow	Market price (per Dth)	(3)	(2) - 4	1
FTRs	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
				Price volatility	(4)	30% - 46%	38	%
Total liabilities	$	7

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

Fair Value Inputs, Liabilities, Quantitative Information

The following table presents Dominion's quantitative information about Level 3 fair value measurements at September 30, 2016. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)	$	85	Discounted cash flow	Market price (per Dth)	(3)	(2) - 7	—
FTRs	7		Discounted cash flow	Market price (per MWh)	(3)	(6) - 6	1
Physical and financial options:
Natural gas	4		Option model	Market price (per Dth)	(3)	2 - 7	3
				Price volatility	(4)	19% - 46%	24	%
Total assets	$	96
Liabilities
Physical and financial forwards and futures:
Natural gas(2)	$	4	Discounted cash flow	Market price (per Dth)	(3)	(2) - 4	1
FTRs	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
				Price volatility	(4)	30% - 46%	38	%
Total liabilities	$	7

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

Significant Unobservable Inputs

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

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)
Price volatility	Buy	Increase (decrease)	Gain (loss)
Price volatility	Sell	Increase (decrease)	Loss (gain)

Recurring Fair Value Measurements

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

	Level 1		Level 2		Level 3		Total
(millions)
At September 30, 2016
Assets
Derivatives:
Commodity	$	—	$	172	$	96	$	268
Interest rate	—		19		—		19
Foreign currency	—		8		—		8
Investments(1):
Equity securities:
United States:
Large cap	2,712		—		—		2,712
REIT	67		—		—		67
Other	6		—		—		6
Non-United States:
Large cap	10		—		—		10
Fixed income:
Corporate debt instruments	—		518		—		518
United States Treasury securities and agency debentures	438		231		—		669
State and municipal	—		372		—		372
Other	—		109		—		109
Cash equivalents and other	8		—		—		8
Total assets	$	3,241	$	1,429	$	96	$	4,766
Liabilities
Derivatives:
Commodity	$	—	$	104	$	7	$	111
Interest rate	—		307		—		307
Foreign currency	—		4		—		4
Total liabilities	$	—	$	415	$	7	$	422
At December 31, 2015
Assets
Derivatives:
Commodity	$	1	$	249	$	114	$	364
Interest rate	—		24		—		24
Investments(1):
Equity securities:
United States:
Large cap	2,547		—		—		2,547
REIT	63		—		—		63
Other	5		—		—		5
Non-United States:
Large cap	10		—		—		10
Fixed income:

Corporate debt instruments	—		437		—		437
United States Treasury securities and agency debentures	458		201		—		659
State and municipal	—		376		—		376
Other	—		100		—		100
Cash equivalents and other	2		2		—		4
Total assets	$	3,086	$	1,389	$	114	$	4,589
Liabilities
Derivatives:
Commodity	$	—	$	141	$	19	$	160
Interest rate	—		183		—		183
Total liabilities	$	—	$	324	$	19	$	343

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

Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

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

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

Fair Value, Unobservable Inputs, Gain (Loss) Included In Earnings

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

	Operating Revenue		Electric Fuel and Other Energy-Related Purchases			Total
(millions)
Three Months Ended September 30, 2016
Total gains (losses) included in earnings	$	—	$	(7	)	$	(7	)
Three Months Ended September 30, 2015
Total gains (losses) included in earnings	$	—	$	(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
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	$	(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

Cost and Fair Value of Financial Instruments Disclosure

For the Companies' financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

	September 30, 2016				December 31, 2015
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	26,287	$	29,077	$	21,873	$	23,210
Junior subordinated notes(3)	2,980		3,030		1,340		1,192
Remarketable subordinated notes(3)	2,371		2,392		2,080		2,129
Virginia Power
Long-term debt, including securities due within one year(3)	$	9,642	$	11,259	$	9,368	$	10,400
Dominion Gas
Long-term debt, including securities due within one year(4)	$	3,945	$	4,139	$	3,269	$	3,299

(1) Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2) Carrying amount includes amounts which represent the unamortized debt issuance costs, discount and/or premium, and foreign currency remeasurement adjustments. At September 30, 2016 and December 31, 2015, includes the valuation of certain fair value hedges associated with fixed rate debt of $14 million and $7 million, respectively.

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

(4) Carrying amount includes amounts which represent the unamortized debt issuance costs, discount and/or premium, and foreign currency remeasurement adjustments.

Virginia Electric and Power Company

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Fair Value Inputs, Assets, Quantitative Information

The following table presents Virginia Power's quantitative information about Level 3 fair value measurements at September 30, 2016. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)	$	81	Discounted cash flow	Market price (per Dth)	(3)	(2) - 7	—
FTRs	7		Discounted cash flow	Market price (per MWh)	(3)	(6) - 6	1
Physical and financial options:
Natural gas	2		Option model	Market price (per Dth)	(3)	2 - 7	3
				Price volatility	(4)	19% - 33%	24	%
Total assets	$	90
Liabilities
Physical and financial forwards and futures:
FTRs	$	2	Discounted cash flow	Market price (per MWh)	(3)	(11) - 6	1
Total liabilities	$	2

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

Fair Value Inputs, Liabilities, Quantitative Information

The following table presents Virginia Power's quantitative information about Level 3 fair value measurements at September 30, 2016. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)	$	81	Discounted cash flow	Market price (per Dth)	(3)	(2) - 7	—
FTRs	7		Discounted cash flow	Market price (per MWh)	(3)	(6) - 6	1
Physical and financial options:
Natural gas	2		Option model	Market price (per Dth)	(3)	2 - 7	3
				Price volatility	(4)	19% - 33%	24	%
Total assets	$	90
Liabilities
Physical and financial forwards and futures:
FTRs	$	2	Discounted cash flow	Market price (per MWh)	(3)	(11) - 6	1
Total liabilities	$	2

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents volatilities unrepresented in published markets.

Significant Unobservable Inputs

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

Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market price	Buy	Increase (decrease)	Gain (loss)
Market price	Sell	Increase (decrease)	Loss (gain)
Price volatility	Buy	Increase (decrease)	Gain (loss)
Price volatility	Sell	Increase (decrease)	Loss (gain)

Recurring Fair Value Measurements

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

	Level 1		Level 2		Level 3		Total
(millions)
At September 30, 2016
Assets
Derivatives:
Commodity	$	—	$	26	$	90	$	116
Interest rate	—		2		—		2
Investments(1):
Equity securities:
United States large cap	1,183		—		—		1,183
REIT	67		—		—		67
Fixed income:
Corporate debt instruments	—		298		—		298
United States Treasury securities and agency debentures	144		107		—		251
State and municipal	—		174		—		174
Other	—		29		—		29
Total assets	$	1,394	$	636	$	90	$	2,120
Liabilities
Derivatives:
Commodity	$	—	$	22	$	2	$	24
Interest rate	—		267		—		267
Total liabilities	$	—	$	289	$	2	$	291
At December 31, 2015
Assets
Derivatives:
Commodity	$	—	$	13	$	101	$	114
Interest rate	—		13		—		13
Investments(1):
Equity securities:
United States large cap	1,100		—		—		1,100
REIT	63		—		—		63
Fixed income:
Corporate debt instruments	—		238		—		238
United States Treasury securities and agency debentures	180		79		—		259
State and municipal	—		175		—		175
Other	—		34		—		34
Total assets	$	1,343	$	552	$	101	$	1,996
Liabilities
Derivatives:
Commodity	$	—	$	19	$	8	$	27
Interest rate	—		59		—		59
Total liabilities	$	—	$	78	$	8	$	86

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

Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
(millions)
Beginning balance	$	125		$	73		$	93		$	102
Total realized and unrealized gains (losses):
Included in earnings	(7		)	(10		)	(24		)	(1		)
Included in regulatory assets/liabilities	(37		)	47			(5		)	18
Settlements	7			10			24			1
Ending balance	$	88		$	120		$	88		$	120

Dominion Gas Holdings, LLC

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Recurring Fair Value Measurements

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

	Level 1		Level 2		Level 3		Total
(millions)
At September 30, 2016
Assets
Commodity	$	—	$	6	$	—	$	6
Foreign currency	—		8		—		8
Total Assets	$	—	$	14	$	—	$	14
Liabilities
Commodity	$	—	$	2	$	—	$	2
Foreign currency	—		4		—		4
Total liabilities	$	—	$	6	$	—	$	6
At December 31, 2015
Assets
Commodity	$	—	$	5	$	6	$	11
Total Assets	$	—	$	5	$	6	$	11
Liabilities
Interest rate	$	—	$	14	$	—	$	14
Total liabilities	$	—	$	14	$	—	$	14

Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

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

XML

Derivatives and Hedge Accounting Activities (Tables)

9 Months Ended

Sep. 30, 2016

Derivative [Line Items]

Offsetting Assets

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

	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
(millions)
Commodity contracts:
Over-the-counter	$	173	$	—	$	173	$	217	$	—	$	217
Exchange	88		—		88		138		—		138
Interest rate contracts:
Over-the-counter	19		—		19		24		—		24
Foreign currency contracts:
Over-the-counter	8		—		8		—		—		—
Total derivatives, subject to a master netting or similar arrangement	288		—		288		379		—		379
Total derivatives, not subject to a master netting or similar arrangement	7		—		7		9		—		9
Total	$	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

Offsetting Liabilities

	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
(millions)
Commodity contracts:
Over-the-counter	$	43	$	—	$	43	$	70	$	—	$	70
Exchange	63		—		63		82		—		82
Interest rate contracts:
Over-the-counter	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	$	422	$	—	$	422	$	343	$	—	$	343

			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 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	$	43	$	20	$	—	$	23	$	70	$	37	$	—	$	33
Exchange	63		63		—		—		82		82		—		—
Interest rate contracts:
Over-the-counter	307		10		—		297		183		22		—		161
Foreign currency contracts:
Over-the-counter	4		4		—		—		—		—		—		—
Total	$	417	$	97	$	—	$	320	$	335	$	141	$	—	$	194

Schedule of Volume of Derivative Activity

The following table presents the volume of Dominion’s derivative activity at 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
Natural Gas (bcf):
Fixed price(1)	104		23
Basis	261		626
Electricity (MWh):
Fixed price	8,274,639		659,440
FTRs	72,352,190		—
Liquids (Gal)(2)	39,269,554		—
Interest rate(3)	$	2,200,000,000	$	1,600,000,000
Foreign currency(3)(4)	$	—	$	280,000,000

(1) Includes options.

(2) Includes NGLs and oil.

(3) Maturity is determined based on final settlement period.

(4) Euro equivalent volumes are €250,000,000.

Cash Flow Hedges Included Accumulated Other Comprehensive Income (Loss)

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

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(2	)	$	(2	)	39 months
Electricity	44			42			15 months
Other	(1		)	(1		)	6 months
Interest rate	(304		)	(26		)	378 months
Foreign currency	2			—			117 months
Total	$	(261	)	$	13

Fair Value of Derivatives

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

	Fair Value – Derivatives under Hedge  Accounting		Fair Value – Derivatives not under Hedge  Accounting		Total Fair Value
(millions)
At September 30, 2016
ASSETS
Current Assets
Commodity	$	59	$	105	$	164
Interest rate	9		—		9
Total current derivative assets(1)	68		105		173
Noncurrent Assets
Commodity	4		100		104
Interest rate	10		—		10
Foreign currency	8		—		8
Total noncurrent derivative assets(2)	22		100		122
Total derivative assets	$	90	$	205	$	295
LIABILITIES
Current Liabilities
Commodity	$	22	$	78	$	100
Interest rate	182		—		182
Foreign currency	4		—		4
Total current derivative liabilities(3)	208		78		286
Noncurrent Liabilities
Commodity	1		10		11
Interest rate	125		—		125
Total noncurrent derivative liabilities(4)	126		10		136
Total derivative liabilities	$	334	$	88	$	422
At December 31, 2015
ASSETS
Current Assets

Commodity	$	101	$	151	$	252
Interest rate	3		—		3
Total current derivative assets(1)	104		151		255
Noncurrent Assets
Commodity	3		109		112
Interest rate	21		—		21
Total noncurrent derivative assets(2)	24		109		133
Total derivative assets	$	128	$	260	$	388
LIABILITIES
Current Liabilities
Commodity	$	32	$	116	$	148
Interest rate	164		—		164
Total current derivative liabilities(3)	196		116		312
Noncurrent Liabilities
Commodity	—		12		12
Interest rate	19		—		19
Total noncurrent derivative liabilities(4)	19		12		31
Total derivative liabilities	$	215	$	128	$	343

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

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

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

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

Gains and Losses on Derivatives in Cash Flow Hedging Relationships

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss)  Recognized in AOCI on Derivatives (Effective Portion) (1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended September 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	64
Purchased gas				(1		)
Electric fuel and other energy-related purchases				(1		)
Total commodity	$	7		$	62		$	—
Interest rate(3)	3			(10		)	(16		)
Foreign currency(4)	12			3			—
Total	$	22		$	55		$	(16	)
Three Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	87
Purchased gas				(2		)
Total commodity	$	64		$	85		$	—
Interest rate(3)	(71		)	(2		)	(69		)
Total	$	(7	)	$	83		$	(69	)
Nine Months Ended September 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	266
Purchased gas				(9		)
Electric fuel and other energy-related purchases				(8		)
Total commodity	$	193		$	249		$	—
Interest rate(3)	(107		)	(21		)	(258		)
Foreign currency(4)	4			1			—
Total	$	90		$	229		$	(258	)
Nine Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	103
Purchased gas				(9		)
Total commodity	$	117		$	94		$	3
Interest rate(3)	(72		)	(7		)	(27		)
Total	$	45		$	87		$	(24	)

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

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

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

(4) Amounts recorded in Dominion’s Consolidated Statements of Income are classified in other income.

Schedule of Derivatives not Designated as Hedging Instruments

	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
	Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives Not Designated as Hedging Instruments	2016			2015			2016			2015
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue	$	25		$	2		$	19		$	20
Purchased gas	(21		)	(3		)	(14		)	(12		)
Electric fuel and other energy-related purchases	(12		)	(4		)	(43		)	5
Interest rate(2)	—			(1		)	—			(1		)
Total	$	(8	)	$	(6	)	$	(38	)	$	12

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

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

Virginia Electric and Power Company

Derivative [Line Items]

Offsetting Assets

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

	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
(millions)
Commodity contracts:
Over-the-counter	$	88	$	—	$	88	$	101	$	—	$	101
Interest rate contracts:
Over-the-counter	2		—		2		13		—		13
Total derivatives, subject to a master netting or similar arrangement	90		—		90		114		—		114
Total derivatives, not subject to a master netting or similar arrangement	28		—		28		13		—		13
Total	$	118	$	—	$	118	$	127	$	—	$	127

			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	$	88	$	2	$	—	$	86	$	101	$	3	$	—	$	98
Interest rate contracts:
Over-the-counter	2		—		—		2		13		10		—		3
Total	$	90	$	2	$	—	$	88	$	114	$	13	$	—	$	101

Offsetting Liabilities

	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
(millions)
Commodity contracts:
Over-the-counter	$	9	$	—	$	9	$	5	$	—	$	5
Interest rate contracts:
Over-the-counter	267		—		267		59		—		59
Total derivatives, subject to a master netting or similar arrangement	276		—		276		64		—		64
Total derivatives, not subject to a master netting or similar arrangement	15		—		15		22		—		22
Total	$	291	$	—	$	291	$	86	$	—	$	86

			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 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	$	9	$	2	$	—	$	7	$	5	$	3	$	—	$	2
Interest rate contracts:
Over-the-counter	267		—		—		267		59		10		—		49
Total	$	276	$	2	$	—	$	274	$	64	$	13	$	—	$	51

Schedule of Volume of Derivative Activity

The following table presents the volume of Virginia Power’s derivative activity at 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
Natural Gas (bcf):
Fixed price(1)	32		12
Basis	126		558
Electricity (MWh):
FTRs	70,978,901		—
Interest rate	$	1,200,000,000	$	600,000,000

(1) Includes options.

Cash Flow Hedges Included Accumulated Other Comprehensive Income (Loss)

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

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

Fair Value of Derivatives

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

Balance Sheets:

	Fair Value – Derivatives under Hedge  Accounting		Fair Value – Derivatives not under Hedge  Accounting		Total Fair Value
(millions)
At September 30, 2016
ASSETS
Current Assets
Commodity	$	—	$	25	$	25
Interest rate	2		—		2
Total current derivative assets(1)	2		25		27
Noncurrent Assets
Commodity	—		91		91
Total noncurrent derivative assets(2)	—		91		91
Total derivative assets	$	2	$	116	$	118
LIABILITIES
Current Liabilities
Commodity	$	—	$	19	$	19
Interest rate	142		—		142
Total current derivative liabilities(3)	142		19		161
Noncurrent Liabilities
Commodity	—		5		5
Interest rate	125		—		125
Total noncurrent derivatives liabilities (4)	125		5		130
Total derivative liabilities	$	267	$	24	$	291
At December 31, 2015
ASSETS
Current Assets
Commodity	$	—	$	18	$	18
Total current derivative assets(1)	—		18		18
Noncurrent Assets
Commodity	—		96		96
Interest rate	13		—		13
Total noncurrent derivative assets(2)	13		96		109
Total derivative assets	$	13	$	114	$	127
LIABILITIES
Current Liabilities
Commodity	$	—	$	23	$	23
Interest rate	57		—		57
Total current derivative liabilities(3)	57		23		80
Noncurrent Liabilities
Commodity	—		4		4
Interest rate	2		—		2
Total noncurrent derivative liabilities(4)	2		4		6
Total derivative liabilities	$	59	$	27	$	86

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

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

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

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

Gains and Losses on Derivatives in Cash Flow Hedging Relationships

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase(Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended September 30, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(2	)	$	—		$	(16	)
Total	$	(2	)	$	—		$	(16	)
Three Months Ended September 30, 2015
Derivative type and location of gains (losses):
Interest rate(3)	$	(9	)	$	—		$	(69	)
Total	$	(9	)	$	—		$	(69	)
Nine Months Ended September 30, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(26	)	$	(1	)	$	(258	)
Total	$	(26	)	$	(1	)	$	(258	)
Nine Months Ended September 30, 2015
Derivative type and location of gains (losses):
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Total commodity	$	—		$	(1	)	$	3
Interest rate(3)	(4		)	—			(27		)
Total	$	(4	)	$	(1	)	$	(24	)

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

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

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

Schedule of Derivatives not Designated as Hedging Instruments

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

(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.

(2) Amounts recorded in Virginia Power's Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.

Dominion Gas Holdings, LLC

Derivative [Line Items]

Offsetting Assets

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

	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
(millions)
Commodity contracts:
Over-the-counter	$	6	$	—	$	6	$	11	$	—	$	11
Foreign currency contracts:
Over-the-counter	8		—		8		—		—		—
Total derivatives, subject to a master netting or similar arrangement	$	14	$	—	$	14	$	11	$	—	$	11

			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	$	6	$	1	$	—	$	5	$	11	$	—	$	—	$	11
Foreign currency contracts:
Over-the-counter	8		4		—		4		—		—		—		—
Total	$	14	$	5	$	—	$	9	$	11	$	—	$	—	$	11

Offsetting Liabilities

	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
(millions)
Commodity contracts:
Over-the-counter	$	2	$	—	$	2	$	—	$	—	$	—
Interest rate contracts:
Over-the-counter	—		—		—		14		—		14
Foreign currency contracts:
Over-the-counter	4		—		4		—		—		—
Total derivatives, subject to a master netting or similar arrangement	$	6	$	—	$	6	$	14	$	—	$	14

			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 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	$	2	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Interest rate contracts:
Over-the-counter	—		—		—		—		14		—		—		14
Foreign currency contracts:
Over-the-counter	4		4		—		—		—		—		—		—
Total	$	6	$	5	$	—	$	1	$	14	$	—	$	—	$	14

Schedule of Volume of Derivative Activity

The following table presents the volume of Dominion Gas' derivative activity at 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
Natural Gas (bcf):
Fixed price	6		—
Basis	6		—
NGLs (Gal)	33,095,554		—
Foreign currency(1)	$	—	$	280,000,000

(1) Maturity is determined based on final settlement period. Euro equivalent volumes are €250,000,000.

Cash Flow Hedges Included Accumulated Other Comprehensive Income (Loss)

The following table presents selected information related to losses on cash flow hedges included in AOCI in Dominion Gas' Consolidated Balance Sheet at September 30, 2016:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
NGLs	$	(1	)	$	(1	)	6 months
Interest rate	(27		)	(2		)	339 months
Foreign currency	2			—			117 months
Total	$	(26	)	$	(3	)

Fair Value of Derivatives

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
(millions)
At September 30, 2016
ASSETS
Current Assets
Commodity	$	1	$	5	$	6
Total current derivative assets(1)	1		5		6
Noncurrent Assets
Foreign currency	8		—		8
Total noncurrent derivative assets(2)	8		—		8
Total derivative assets	$	9	$	5	$	14
LIABILITIES
Current Liabilities
Commodity	$	2	$	—	$	2
Foreign currency	4		—		4
Total current derivative liabilities(3)	6		—		6
Total derivative liabilities	$	6	$	—	$	6
At December 31, 2015
ASSETS
Current Assets
Commodity	$	10	$	—	$	10
Total current derivative assets(1)	10		—		10
Noncurrent Assets
Commodity	1		—		1
Total noncurrent derivatives assets(2)	1		—		1
Total derivative assets	$	11	$	—	$	11
LIABILITIES
Noncurrent Liabilities
Interest rate	$	14	$	—	$	14
Total noncurrent derivative liabilities(4)	14		—		14
Total derivative liabilities	$	14	$	—	$	14

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

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

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

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

Gains and Losses on Derivatives in Cash Flow Hedging Relationships

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income
(millions)
Three Months Ended September 30, 2016
Derivative Type and Location of Gains (Losses):
Commodity:
Operating revenue				$	1
Total commodity	$	—		$	1
Interest rate(2)	—			(1		)
Foreign currency(3)	12			3
Total	$	12		$	3
Three Months Ended September 30, 2015
Derivative Type and Location of Gains (Losses):
Commodity:
Operating revenue				$	3
Total commodity	$	11		$	3
Interest rate(2)	(7		)	—
Total	$	4		$	3
Nine Months Ended September 30, 2016
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	6
Total commodity	$	(7	)	$	6
Interest rate(2)	(8		)	(2		)
Foreign currency(3)	4			1
Total	$	(11	)	$	5
Nine Months Ended September 30, 2015
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	4
Total commodity	$	10		$	4
Interest rate(2)	(8		)	—
Total	$	2		$	4

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

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

(3) Amounts recorded in Dominion Gas' Consolidated Statements of Income are classified in other income.

Schedule of Derivatives not Designated as Hedging Instruments

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

XML

Investments (Tables)

9 Months Ended

Sep. 30, 2016

Gain (Loss) on Investments [Line Items]

Available-For-Sale Securities

Dominion’s decommissioning trust funds are summarized below:

	Amortized Cost		Total  Unrealized Gains(1)		Total  Unrealized Losses(1)				Fair Value
(millions)
At September 30, 2016
Marketable equity securities:
United States large cap	$	1,361	$	1,312	$	—			$	2,673
REIT	59		8		—				67
Marketable debt securities:
Corporate bonds	493		26		(1		)		518
United States Treasury securities and agency debentures	645		21		—				666
State and municipal	306		27		—				333
Other	89		—		—				89
Cost method investments	69		—		—				69
Cash equivalents and other(2)	12		—		—				12
Total	$	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
REIT	59		4		—				63
Marketable debt securities:
Corporate bonds	433		11		(7		)		437
United States Treasury securities and agency debentures	654		8		(4		)		658
State and municipal	312		22		—				334
Other	99		—		—				99
Cost method investments	70		—		—				70
Cash equivalents and other(2)	14		—		—				14
Total	$	2,936	$	1,258	$	(11	)	(3)	$	4,183

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

(2) Includes pending sales of securities of $9 million and $12 million at September 30, 2016 and December 31, 2015, respectively.

(3) The fair value of securities in an unrealized loss position was $156 million and $592 million at September 30, 2016 and December 31, 2015, respectively.

Investments Classified by Contractual Maturity Date

The fair value of Dominion’s marketable debt securities held in nuclear decommissioning trust funds at 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

Marketable Securities

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Proceeds from sales	$	300	$	357	$	1,009	$	937
Realized gains(1)	40		65		102		165
Realized losses(1)	9		40		43		69

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

Other Than Temporary Impairment Losses On Investment Securities

Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
(millions)
Total other-than-temporary impairment losses(1)	$	9		$	29		$	34		$	55
Losses recorded to the nuclear decommissioning trust regulatory liability	(4		)	(10		)	(15		)	(21		)
Losses recognized in other comprehensive income (before taxes)	—			(3		)	(1		)	(7		)
Net impairment losses recognized in earnings	$	5		$	16		$	18		$	27

(1) Amounts include other-than-temporary impairment losses for debt securities of less than $1 million and $3 million for the three months ended September 30, 2016 and 2015, respectively, and $2 million and $7 million for the nine months ended September 30, 2016 and 2015, respectively.

Virginia Electric and Power Company

Gain (Loss) on Investments [Line Items]

Available-For-Sale Securities

Virginia Power’s decommissioning trust funds are summarized below:

	Amortized Cost		Total  Unrealized Gains(1)		Total  Unrealized Losses(1)				Fair Value
(millions)
At September 30, 2016
Marketable equity securities:
United States large cap	$	606	$	576	$	—			$	1,182
REIT	59		8		—				67
Marketable debt securities:
Corporate bonds	285		13		—				298
United States Treasury securities and agency debentures	246		5		—				251
State and municipal	158		15		—				173
Other	29		—		—				29
Cost method investments	69		—		—				69
Cash equivalents and other(2)	5		—		—				5
Total	$	1,457	$	617	$	—		(3)	$	2,074
At December 31, 2015
Marketable equity securities:
United States large cap	$	574	$	525	$	—			$	1,099
REIT	59		4		—				63
Marketable debt securities:
Corporate bonds	237		5		(4		)		238
United States Treasury securities and agency debentures	260		1		(2		)		259
State and municipal	162		13		(1		)		174
Other	34		—		—				34
Cost method investments	70		—		—				70
Cash equivalents and other(2)	8		—		—				8
Total	$	1,404	$	548	$	(7	)	(3)	$	1,945

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

(2) Includes pending sales of securities of $4 million and $8 million at September 30, 2016 and December 31, 2015, respectively.

(3) The fair value of securities in an unrealized loss position was $91 million and $281 million at September 30, 2016 and December 31, 2015, respectively.

Investments Classified by Contractual Maturity Date

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

	Amount
(millions)
Due in one year or less	$	51
Due after one year through five years	228
Due after five years through ten years	202
Due after ten years	270
Total	$	751

Marketable Securities

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Proceeds from sales	$	131	$	198	$	478	$	407
Realized gains(1)	18		45		48		82
Realized losses(1)	4		18		21		33

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

XML

Regulatory Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2016

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets

Regulatory assets and liabilities include the following:

	September 30, 2016		December 31, 2015
(millions)
Dominion
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	101	$	90
Deferred nuclear refueling outage costs(2)	60		75
Deferred cost of fuel used in electric generation(3)	3		111
Other	86		75
Regulatory assets-current(4)	250		351
Unrecognized pension and other postretirement benefit costs(5)	981		1,015
Derivatives(6)	366		110
Deferred rate adjustment clause costs(1)	271		295
PJM transmission rates(7)	192		192
Income taxes recoverable through future rates(8)	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
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)	21		20
Other	82		65
Regulatory assets-non-current(13)	469		449
Total regulatory assets	$	491	$	472
Regulatory liabilities:
PIPP(9)	$	26	$	46
Other	13		9

Regulatory liabilities-current(10)	39		55
Provision for future cost of removal and AROs(11)	173		170
Other	44		31
Regulatory liabilities-non-current(14)	217		201
Total regulatory liabilities	$	256	$	256

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

(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 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.

Schedule of Regulatory Liabilities

Regulatory assets and liabilities include the following:

	September 30, 2016		December 31, 2015
(millions)
Dominion
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	101	$	90
Deferred nuclear refueling outage costs(2)	60		75
Deferred cost of fuel used in electric generation(3)	3		111
Other	86		75
Regulatory assets-current(4)	250		351
Unrecognized pension and other postretirement benefit costs(5)	981		1,015
Derivatives(6)	366		110
Deferred rate adjustment clause costs(1)	271		295
PJM transmission rates(7)	192		192
Income taxes recoverable through future rates(8)	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
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)	21		20
Other	82		65
Regulatory assets-non-current(13)	469		449
Total regulatory assets	$	491	$	472
Regulatory liabilities:
PIPP(9)	$	26	$	46
Other	13		9

Regulatory liabilities-current(10)	39		55
Provision for future cost of removal and AROs(11)	173		170
Other	44		31
Regulatory liabilities-non-current(14)	217		201
Total regulatory liabilities	$	256	$	256

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

(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 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.

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Significant Financing Transactions (Tables)

9 Months Ended

Sep. 30, 2016

Debt Instrument [Line Items]

Schedule of Line of Credit Facilities

At 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
(millions)
Joint revolving credit facility(1)	$	5,000	$	3,073	$	—	$	1,927
Joint revolving credit facility(1)	500		—		60		440
Revolving multi-year credit facility(2)	500		24		—		476
Revolving 364-day credit facility(2)	250		—		—		250
Total	$	6,250	$	3,097	$	60	$	3,093

(1) In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

(2) These Dominion Questar facilities were terminated in October 2016.

Schedule of Capital Units

Selected information about Dominion’s 2016 Equity Units is presented below:

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

(1) Annual interest rate applies to each of the Series A-1 RSNs and Series A-2 RSNs.

(2) The maturity dates of the $700 million Series A-1 RSNs and $700 million Series A-2 RSNs are August 15, 2021 and August 15, 2024, respectively.

Virginia Electric and Power Company

Debt Instrument [Line Items]

Schedule of Line of Credit Facilities

At 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
(millions)
Joint revolving credit facility(1)	$	5,000	$	965	$	—
Joint revolving credit facility(1)	500		—		—
Total	$	5,500	$	965	$	—

(1) The full amount of the facilities is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion and Dominion Gas. Sub-limits for Virginia Power are set within the facility limit but can be changed at the option of the Companies multiple times per year. At September 30, 2016, the aggregate sub-limit for Virginia Power was $2.0 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion. In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

Dominion Gas Holdings, LLC

Debt Instrument [Line Items]

Schedule of Line of Credit Facilities

At 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
(millions)
Joint revolving credit facility(1)	$	1,000	$	60	$	—
Joint revolving credit facility(1)	500		—		—
Total	$	1,500	$	60	$	—

(1) A maximum of a combined $1.5 billion of the facilities is available to Dominion Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion and Virginia Power. Sub-limits for Dominion Gas are set within the facility limit but can be changed at the option of the Companies multiple times per year. In September 2016, the aggregate sub-limit for Dominion Gas was decreased from $1.0 billion to $750 million. If Dominion Gas has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion. In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Schedule Of Subsidiary Guarantees

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

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	27	$	27
Commodity transactions(3)	2,081		874
Nuclear obligations(4)	169		94
Cove Point(5)	1,900		—
Solar(6)	1,847		539
Other(7)	783		60
Total	$	6,807	$	1,594

(1) Represents the estimated portion of the guarantee's stated limit that is utilized as of September 30, 2016 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

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

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

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

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

(6) Includes guarantees related to solar projects including guarantees that do not have stated limits. Also includes guarantees related to solar projects entered into by DEI on behalf of certain subsidiaries. 

(7) Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries' obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of September 30, 2016, Dominion's maximum remaining cumulative exposure under these equity funding agreements is $36 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits.

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Related-Party Transactions (Tables)

9 Months Ended

Sep. 30, 2016

Virginia Electric and Power Company

Related Party Transaction [Line Items]

Transactions With Affiliates

Presented below are Virginia Power's significant transactions with DRS and other affiliates:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Commodity purchases from affiliates	$	172	$	123	$	416	$	469
Services provided by affiliates(1)	105		96		347		313
Services provided to affiliates	5		5		17		15

(1) Includes capitalized expenditures of $32 million for both the three months ended September 30, 2016 and 2015, and $109 million and $105 million for the nine months ended September 30, 2016 and 2015, respectively.

Dominion Gas Holdings, LLC

Related Party Transaction [Line Items]

Schedule of Related Party Transactions

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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
(millions)
Purchases of natural gas and transportation and storage services from affiliates	$	2	$	3	$	7	$	7
Sales of natural gas and transportation and storage services to affiliates	16		17		51		52
Services provided by related parties(1)	36		30		108		99
Services provided to related parties (2)	34		30		94		75

(1) Includes capitalized expenditures of $13 million and $16 million for the three months ended September 30, 2016 and 2015, respectively, and $37 million and $40 million for the nine months ended September 30, 2016 and 2015, respectively.

(2) Amounts primarily attributable to Atlantic Coast Pipeline.

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

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

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2016

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Net Periodic Benefit Cost

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

	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016			2015
(millions)
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	$	87		$	95		$	23		$	30
Interest cost	234			215			50			50
Expected return on plan assets	(419		)	(398		)	(87		)	(88		)
Amortization of prior service cost (credit)	1			1			(23		)	(20		)
Amortization of net actuarial loss	84			120			5			4
Net periodic benefit cost (credit)	$	(13	)	$	33		$	(32	)	$	(24	)

Dominion Gas Holdings, LLC

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Net Periodic Benefit Cost

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
	2016			2015			2016			2015
(millions)
Three Months Ended September 30,
Service cost	$	3		$	4		$	1		$	2
Interest cost	7			7			3			3
Expected return on plan assets	(33		)	(31		)	(5		)	(6		)
Amortization of net actuarial loss	3			5			—			1
Net periodic benefit credit	$	(20	)	$	(15	)	$	(1	)	$	—
Nine Months Ended September 30,
Service cost	$	10		$	11		$	4		$	5
Interest cost	22			21			10			10
Expected return on plan assets	(100		)	(94		)	(17		)	(18		)
Amortization of net actuarial loss	10			15			1			2
Net periodic benefit credit	$	(58	)	$	(47	)	$	(2	)	$	(1	)

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Operating Segments (Tables)

9 Months Ended

Sep. 30, 2016

Segment Reporting Information [Line Items]

Segment Reporting Disclosure Other Information

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

Primary Operating Segment	Description of Operations	Dominion	Virginia Power	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

(1) Includes remaining producer services activities for Dominion.

(2) As a result of Dominion's decision to realign its business units effective for 2015 year-end reporting, nonregulated retail energy marketing operations were moved from the Dominion Generation segment to the Dominion Energy segment.

Schedule of Segment Reporting Information, by Segment

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
(millions)
Three Months Ended September 30, 2016
Total revenue from external customers	$	614	$	1,947	$	359	$	2		$	210		$	3,132
Intersegment revenue	6		2		205		144			(357		)	—
Total operating revenue	620		1,949		564		146			(147		)	3,132
Net income (loss) attributable to Dominion	139		650		135		(234		)	—			690
Three Months Ended September 30, 2015
Total revenue from external customers	$	539	$	1,892	$	377	$	—		$	163		$	2,971
Intersegment revenue	4		2		159		128			(293		)	—
Total operating revenue	543		1,894		536		128			(130		)	2,971
Net income (loss) attributable to Dominion	125		390		153		(75		)	—			593
Nine Months Ended September 30, 2016
Total revenue from external customers	$	1,682	$	5,204	$	1,235	$	8		$	522		$	8,651
Intersegment revenue	17		7		507		469			(1,000		)	—
Total operating revenue	1,699		5,211		1,742		477			(478		)	8,651
Net income (loss) attributable to Dominion	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

(1) 2015 amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Energy segment.

Virginia Electric and Power Company

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment

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

	DVP		Dominion Generation		Corporate and Other			Consolidated Total
(millions)
Three Months Ended September 30, 2016
Operating revenue	$	617	$	1,594	$	—		$	2,211
Net income	140		359		4			503
Three Months Ended September 30, 2015
Operating revenue	$	541	$	1,523	$	(6	)	$	2,058
Net income (loss)	125		273		(13		)	385
Nine Months Ended September 30, 2016
Operating revenue	$	1,686	$	4,191	$	—		$	5,877
Net income (loss)	362		699		(15		)	1,046
Nine Months Ended September 30, 2015
Operating revenue	$	1,610	$	4,419	$	(21	)	$	6,008
Net income (loss)	382		618		(100		)	900

Dominion Gas Holdings, LLC

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment

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

	Dominion Energy		Corporate and Other			Consolidated Total
(millions)
Three Months Ended September 30, 2016
Operating revenue	$	382	$	—		$	382
Net income	77		6			83
Three Months Ended September 30, 2015
Operating revenue	$	365	$	—		$	365
Net income (loss)	113		(2		)	111
Nine Months Ended September 30, 2016
Operating revenue	$	1,181	$	—		$	1,181
Net income (loss)	288		(2		)	286
Nine Months Ended September 30, 2015
Operating revenue	$	1,291	$	—		$	1,291
Net income (loss)	364		(7		)	357

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Significant Accounting Policies (Narrative) (Details)	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Merchant Solar Projects
Subsidiary, Sale of Stock [Line Items]
Percentage of equity interest sold to noncontrolling interest owners	33.00%	33.00%
Four Brothers and Three Cedars
Subsidiary, Sale of Stock [Line Items]
Percentage ownership in total units	50.00%
Dominion Midstream Partners, LP
Subsidiary, Sale of Stock [Line Items]
Ownership interest percentage of limited partner interests	65.00%

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Acquisitions and Dispositions (Acquisition of Dominion Questar) (Narrative) (Details) $ / shares in Units, shares in Thousands, MMcf in Thousands		1 Months Ended				3 Months Ended		9 Months Ended
	Sep. 16, 2016 USD ($) mi $ / shares shares MMcf	Oct. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Aug. 31, 2016 USD ($)	Apr. 30, 2016 USD ($)	Dec. 31, 2016 USD ($) shares	Sep. 30, 2016 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)
Business Acquisition [Line Items]
Issuance of common stock								$ 2,079,000,000
Issuance of short-term notes								1,200,000,000	$ 0
Issuance of common stock								2,079,000,000	717,000,000
Contributions to fund Dominion Questar's qualified and non-qualified defined benefit pension plans								12,000,000
Other Commitment, Fiscal Year Maturity [Abstract]
Repayments of short term note								600,000,000	$ 0
Subsequent Event | Questar Pipeline | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Dominion Midstream Partners, LP | Subsidiary of Common Parent
Other Commitment, Fiscal Year Maturity [Abstract]
Debt financed distribution		$ 300,000,000
Total consideration		1,300,000,000
Subsequent Event | Questar Pipeline | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Dominion Midstream Partners, LP | Subsidiary of Common Parent | Minimum
Other Commitment, Fiscal Year Maturity [Abstract]
Cash consideration		565,000,000
Subsequent Event | Questar Pipeline | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Dominion Midstream Partners, LP | Subsidiary of Common Parent | Maximum
Other Commitment, Fiscal Year Maturity [Abstract]
Cash consideration		890,000,000
Subsequent Event | Questar Pipeline | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Dominion Midstream Partners, LP | Subsidiary of Common Parent | Partnership Interest | Minimum
Other Commitment, Fiscal Year Maturity [Abstract]
Combined value of common and convertible preferred units		400,000,000
Subsequent Event | Questar Pipeline | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Dominion Midstream Partners, LP | Subsidiary of Common Parent | Partnership Interest | Maximum
Other Commitment, Fiscal Year Maturity [Abstract]
Combined value of common and convertible preferred units		$ 725,000,000
Subsequent Event | Questar Pipeline | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Scenario, Forecast | Dominion Midstream Partners, LP | Limited Partner | Common Units
Other Commitment, Fiscal Year Maturity [Abstract]
Common units to be purchased | shares						6,657
Senior Unsecured Promissory Note Payable | Subsequent Event | Questar Pipeline | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Scenario, Forecast | Dominion Midstream Partners, LP | Limited Partner | Term loan
Other Commitment, Fiscal Year Maturity [Abstract]
Repayment of term loan						$ 301,000,000
Private Placement Term Loan Agreement Maturing in September 2017 | Term loan agreement | Subsequent Event | Questar Pipeline | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Scenario, Forecast
Other Commitment, Fiscal Year Maturity [Abstract]
Repayments of short term note						$ 1,200,000,000
Underwritten Public Offering
Business Acquisition [Line Items]
Issuance of common stock					$ 756,000,000
Series A RSNs
Business Acquisition [Line Items]
Issuance of common stock				$ 1,400,000,000.0
Dominion Questar Corporation
Business Acquisition [Line Items]
Gas storage (bcf) | MMcf	56
Price per share | $ / shares	$ 25.00
Total consideration	$ 4,400,000,000
Shares of Dominion Questar outstanding at closing | shares	175,500
August 2016 issuance of senior notes				1,300,000,000
Contributions to fund Dominion Questar's qualified and non-qualified defined benefit pension plans	$ 75,000,000
Period after the closing date	6 months
Other Commitment, Fiscal Year Maturity [Abstract]
Increase in operating revenue							$ 23,000,000	23,000,000
Increase in net income							5,000,000	5,000,000
Dominion Questar Corporation | Other operations and maintenance
Other Commitment, Fiscal Year Maturity [Abstract]
Transaction and transition costs incurred							40,000,000	47,000,000
Dominion Questar Corporation | Interest and related charges
Other Commitment, Fiscal Year Maturity [Abstract]
Transaction and transition costs incurred							$ 13,000,000	$ 13,000,000
Dominion Questar Corporation | White River Hub, LLC
Business Acquisition [Line Items]
Percentage interest	50.00%
Dominion Questar Corporation | Commitment for Charitable Contributions
Other Commitment, Fiscal Year Maturity [Abstract]
Charitable contributions, next twelve months	$ 1,000,000
Charitable contributions, second year	1,000,000
Charitable contributions, third year	1,000,000
Charitable contributions, fourth year	1,000,000
Charitable contributions, fifth year	$ 1,000,000
Dominion Questar Corporation | Commitment for Charitable Contributions | Minimum
Other Commitment, Fiscal Year Maturity [Abstract]
Period for charitable contributions	5 years
Dominion Questar Corporation | Term loan agreement
Business Acquisition [Line Items]
Issuance of short-term notes			$ 1,200,000,000
Dominion Questar Corporation | Underwritten Public Offering
Business Acquisition [Line Items]
Issuance of common stock					$ 500,000,000
Dominion Questar Corporation | Series A RSNs
Business Acquisition [Line Items]
Issuance of common stock				$ 1,400,000,000
Dominion Questar Corporation | Gas Transmission Pipeline
Business Acquisition [Line Items]
Length of natural gas pipeline (in miles) | mi	3,400
Dominion Questar Corporation | Gas Distribution Pipeline
Business Acquisition [Line Items]
Length of natural gas pipeline (in miles) | mi	27,500

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Acquisitions and Dispositions (Schedule of Preliminary Allocation of Purchase Price to Assets Acquired and Liabilities Assumed) (Details) - USD ($) $ in Millions		Sep. 16, 2016	Sep. 30, 2016	Dec. 31, 2015	[1]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]
Goodwill			$ 6,405	$ 3,294
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Short-term debt outstanding			$ 3,097	$ 3,509
Dominion Questar Corporation
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]
Total current assets		$ 224
Investments	[2]	58
Property, plant and equipment	[3]	4,120
Goodwill		3,111
Total deferred charges and other assets, excluding goodwill		75
Total Assets		7,588
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Total current liabilities	[4]	791
Long-term debt	[5]	963
Deferred income taxes		798
Regulatory liabilities		259
Asset retirement obligations		160
Other deferred credits and other liabilities	[6]	220
Total Liabilities		3,191
Total estimated purchase price		4,397
Short term debt		301
Short-term debt outstanding		24
Capital lease obligation		35
Capital Leases, Future Minimum Payments, Net Present Value [Abstract]
Remaining in 2016		1
2017		4
2018		4
2019		4
2020		4
Remaining payments thereafter		37
Dominion Questar Corporation | Short Term Note, Variable Rate, Maturing in February 2017
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Short-term note outstanding		$ 250
Dominion Questar Corporation | Minimum
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Useful lives		9 years
Dominion Questar Corporation | Minimum | Unsecured Senior Notes, Maturities Range from 2017 to 2048 | Unsecured Senior Notes
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Interest rate percentage		2.98%
Dominion Questar Corporation | Maximum
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Useful lives		18 years
Dominion Questar Corporation | Maximum | Unsecured Senior Notes, Maturities Range from 2017 to 2048 | Unsecured Senior Notes
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Interest rate percentage		7.20%
Dominion Questar Corporation | White River Hub, LLC
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities [Abstract]
Equity method investment		$ 40

[1] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[2] Includes $40 million for an equity method investment in White River Hub. The fair value adjustment on the equity method investment in White River Hub is considered to be equity method goodwill and is not amortized.

[3] Nonregulated property, plant and equipment, excluding land, will be depreciated over remaining useful lives primarily ranging from 9 to 18 years.

[4] Includes $301 million of short-term debt, of which $24 million is outstanding at September 30, 2016, as well as a $250 million short-term note which matures in February 2017 and bears interest at a variable rate.

[5] Unsecured senior notes have maturities which range from 2017 to 2048 and bear interest at rates from 2.98% to 7.20%.

[6] Includes a $35 million capital lease obligation with undiscounted future minimum lease payments of $1 million remaining in 2016, $4 million per year for 2017 through 2020, and $37 million in total thereafter.

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Acquisitions and Dispositions (Schedule of Unaudited Pro Forma Information) (Details) - Dominion Questar Corporation - USD ($) $ / shares in Units, $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2016	[1]	Sep. 30, 2015	Sep. 30, 2016	[1]	Sep. 30, 2015
Business Acquisition [Line Items]
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

[1] Amounts include adjustments for non-recurring costs directly related to the Dominion Questar Combination.

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Acquisitions and Dispositions (Narrative) (Details) $ / shares in Units, a in Thousands, $ in Millions		1 Months Ended												3 Months Ended		9 Months Ended		15 Months Ended
	Apr. 01, 2015 USD ($) $ / shares shares	Sep. 30, 2016 USD ($) MW	Aug. 31, 2016 USD ($) project MW	Jul. 31, 2016 USD ($) a	Apr. 30, 2016 USD ($) a	Jan. 31, 2016 USD ($) a	Dec. 31, 2015 USD ($) project		Sep. 30, 2015 USD ($) a field project MW	Jun. 30, 2015 USD ($) project	Mar. 31, 2015 USD ($) a field	Jan. 31, 2015 USD ($) mi	Dec. 31, 2013 USD ($) a field	Dec. 31, 2017 USD ($)	Sep. 30, 2016 USD ($) MW	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($) a field project	Sep. 30, 2016 USD ($)	Nov. 30, 2016	Nov. 30, 2014 a field
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cost of project																$ 21	$ 278
Contributions from SunEdison to Four Brothers and Three Cedars																178
Goodwill		$ 6,405					$ 3,294	[1]							$ 6,405	$ 6,405		$ 6,405
Merchant Solar Projects | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
MW Capacity | MW									425
Percentage of equity interest sold to noncontrolling interest owners		33.00%							33.00%						33.00%	33.00%	33.00%	33.00%
Number of solar projects | project									24								24
Total number of solar projects related to potential sale | project							15
Amount of consideration (up to $200 million for assignment of shale development rights)						$ 117	$ 184
Dominion Gas Holdings, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill		$ 542					$ 542	[2]							$ 542	$ 542		$ 542
Dominion Gas Holdings, LLC | Marcellus Shale | Shale development rights
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Amount of consideration (up to $200 million for assignment of shale development rights)				$ 5		$ 5					$ 27		$ 200
Development rights (number of acres) | a				2		2					11		79							24
Number of natural gas storage fields | field											1		1							1
Duration of conveyance of rights													9 years
Dominion Gas Holdings, LLC | Marcellus Shale | Shale development rights | Other operations and maintenance
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of assets				$ 5		$ 5					$ 27
After tax gain on sale of assets				$ 3		$ 3					$ 16
Dominion Gas Holdings, LLC | Marcellus Shale | Shale development rights | Amended Agreement to Extend Conveyance of Development Rights
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Development rights (number of acres) | a					70						9
Duration of conveyance of rights											2 years
Partial interest in remaining acres conveyed (percentage)					32.00%
Dominion Gas Holdings, LLC | Marcellus Shale | Shale development rights | Amended Agreement to Extend Conveyance of Development Rights | Other operations and maintenance
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred revenue recognized from conveyance of rights					$ 35						$ 43
Deferred revenue recognized from conveyance of rights, after tax					$ 21						$ 27
Dominion Gas Holdings, LLC | Utica and Point Pleasant Shale | Shale development rights
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Amount of consideration (up to $200 million for assignment of shale development rights)									$ 52								$ 52
Development rights (number of acres) | a									16								16
Number of natural gas storage fields | field									1								1
Proceeds received with conveyance of acreage									$ 52
Dominion Gas Holdings, LLC | Utica and Point Pleasant Shale | Shale development rights | Other operations and maintenance
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of assets									52
After tax gain on sale of assets									29
Terra Nova Renewable Partners | Call Option | Merchant Solar Projects
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage ownership in total units		67.00%													67.00%	67.00%		67.00%
Dominion Midstream Partners, LP | DCG | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Affiliate
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Amount of consideration (up to $200 million for assignment of shale development rights)	$ 501
Percentage of equity interests contributed	100.00%
Dominion Midstream Partners, LP | DCG | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Affiliate | Partnership Interest
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of common units issued | shares	5,112,139
Value of common units issued	$ 200
Number of trading days used to determine weighted average trading price	10 days
Dominion Midstream Partners, LP | DCG | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Affiliate | Partnership Interest | Weighted Average
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Price per unit | $ / shares	$ 39.12
Dominion Midstream Partners, LP | DCG | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Affiliate | Senior unsecured promissory note payable by Dominion Midstream | Unsecured Promissory Note Receivable
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Term of senior unsecured promissory note payable to Dominion	2 years
Amount of senior unsecured promissory note payable to Dominion	$ 301
Annual interest rate percentage for senior unsecured promissory note payable to Dominion	0.60%
Four Brothers and Three Cedars
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage ownership in total units		50.00%													50.00%	50.00%		50.00%
Four Brothers and Three Cedars | SunEdison, Inc
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contributions from SunEdison to Four Brothers and Three Cedars																		$ 281
Four Brothers and Three Cedars | Federal | Investment Tax Credits
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of expected federal investment tax credits on projects to be claimed		99.00%													99.00%	99.00%		99.00%
Four Brothers and Three Cedars | Scenario, Forecast | Subsequent Event | NRG
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of equity interests acquired																			50.00%
Four Brothers
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition price										$ 64
Liabilities incurred										$ 62
Cost of project															$ 670
Percentage of equity interests acquired										50.00%
Acquisition price in cash										$ 2
Purchase price										64
Net property, plant and equipment acquired										89
Non-controlling interest										$ 25
Number of Projects | project										4
MW Capacity | MW															320
Four Brothers | Other Current Liabilities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payable at period end		$ 7													$ 7	$ 7		$ 7
Three Cedars
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition price									43
Liabilities incurred									$ 37
Cost of project															$ 450
Percentage of equity interests acquired									50.00%								50.00%
Acquisition price in cash									$ 6
Purchase price									43								$ 43
Net property, plant and equipment acquired									65								65
Non-controlling interest									$ 22								$ 22
Number of Projects | project									3
MW Capacity | MW															210
Three Cedars | Other Current Liabilities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payable at period end		$ 4													$ 4	$ 4		$ 4
Solar Frontier Americas Holding, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition price			$ 128
Percentage of equity interests acquired			100.00%
Number of Projects | project			2
MW Capacity | MW			50
Solar Frontier Americas Holding, LLC | Scenario, Forecast
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cost of project														$ 130
Virginia Solar, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of equity interests acquired			100.00%
Number of Projects | project			4
MW Capacity | MW			80
Virginia Solar, LLC | Scenario, Forecast
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cost of project														160
Community Energy Solar, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of equity interests acquired		100.00%													100.00%	100.00%		100.00%
MW Capacity | MW		100
Community Energy Solar, LLC | Scenario, Forecast
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cost of project														$ 210
DCG
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition price												$ 497
Percentage of equity interests acquired												100.00%
Net property, plant and equipment acquired												$ 277
Length of natural gas pipeline (in miles) (nearly 1,500 miles) | mi												1,500
Goodwill												$ 250
Goodwill expected to be deductible for income tax purposes												225
Regulatory liabilities assumed												$ 38

[1] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[2] Dominion Gas’ Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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Acquisitions and Dispositions (Schedule of Acquisitions of Solar Projects) (Details) $ in Millions		1 Months Ended				2 Months Ended				9 Months Ended
		Aug. 31, 2015 USD ($)	Jul. 31, 2015 USD ($)	Apr. 30, 2015 USD ($) project MW		Aug. 31, 2015 USD ($) project MW	Jul. 31, 2015 USD ($) project MW	May 31, 2015 USD ($)		Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)
Business Acquisition [Line Items]
Acquisition of solar development projects										$ 21	$ 278
EC&R NA Solar PV, LLC
Business Acquisition [Line Items]
Number of Projects | project				1
Initial Acquisition Cost	[1]			$ 66
Acquisition of solar development projects	[2]							$ 66
MW Capacity | MW				20
EDF Renewable Development, Inc.
Business Acquisition [Line Items]
Number of Projects | project				3	[3]		1
Initial Acquisition Cost	[1]			$ 106	[3]		$ 68
Acquisition of solar development projects	[2]		$ 68					$ 106	[3]
MW Capacity | MW				24	[3]		18
SunPeak Solar, LLC
Business Acquisition [Line Items]
Number of Projects | project						1
Initial Acquisition Cost	[1]					$ 42
Acquisition of solar development projects	[2]	$ 71
MW Capacity | MW						20

[1] The purchase price was primarily allocated to Property, Plant and Equipment.

[2] Includes acquisition cost.

[3] One of the projects, Marin Carport, began commercial operations in 2016.

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Operating Revenue (Schedule of Operating Revenue) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
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 Electric and Power Company
Electric sales:
Regulated		2,147	2,020	5,707	5,911
Gas sales:
Other		64	38	170	97
Total operating revenue	[1]	2,211	2,058	5,877	6,008
Dominion Gas Holdings, LLC
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	[2]	$ 382	$ 365	$ 1,181	$ 1,291

[1] See Note 17 for amounts attributable to affiliates.

[2] See Note 17 for amounts attributable to related parties.

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Income Taxes (Reconciliation of Income Taxes at the U.S. Statutory Federal Rate as Compared to the Income Tax Expense Recorded in Our Consolidated Statements of Income) (Details)	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating Loss Carryforwards [Line Items]
United States statutory rate	35.00%	35.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.70%	4.00%
Investment tax credits	(10.40%)	(3.50%)
Production tax credits	(0.80%)	(0.80%)
State legislative change	(0.80%)	(0.20%)
Other, net	(2.10%)	(0.70%)
Effective tax rate	24.60%	33.80%
Virginia Electric and Power Company
Operating Loss Carryforwards [Line Items]
United States statutory rate	35.00%	35.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	3.90%	4.20%
Investment tax credits	(0.00%)	(0.00%)
Production tax credits	(0.50%)	(0.50%)
State legislative change	0.00%	0.00%
Other, net	(0.50%)	(0.20%)
Effective tax rate	37.90%	38.50%
Dominion Gas Holdings, LLC
Operating Loss Carryforwards [Line Items]
United States statutory rate	35.00%	35.00%
Increases (reductions) resulting from:
State taxes, net of federal benefit	0.80%	4.10%
Investment tax credits	(0.00%)	(0.00%)
Production tax credits	(0.00%)	(0.00%)
State legislative change	0.00%	0.00%
Other, net	0.40%	0.40%
Effective tax rate	36.20%	39.50%

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Income Taxes (Narrative) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Income Tax Disclosure [Abstract]
Previously unrecognized tax benefits	$ 23
Settlement with tax authority	12
Legislative change	$ 11

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Earnings Per Share (Calculation of Basic and Diluted EPS) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net income attributable to Dominion		$ 690	$ 593	$ 1,666	$ 1,542
Average shares of common stock outstanding – Basic (shares)		625.9	594.6	612.8	591.3
Net effect of dilutive securities (shares)	[1]	0.1	0.9	1.0	1.4
Average shares of common stock outstanding – Diluted (shares)		626.0	595.5	613.8	592.7
Earnings Per Common Share – Basic (in dollars per share)		$ 1.10	$ 1.00	$ 2.72	$ 2.61
Earnings Per Common Share – Diluted (in dollars per share)		$ 1.10	$ 1.00	$ 2.71	$ 2.60

[1] Dilutive securities consist primarily of the 2013 Equity Units for the nine months ended September 30, 2016 and the three and nine months ended September 30, 2015. See Note 14 in this report and Note 17 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 2015 for more information.

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Accumulated Other Comprehensive Income (Schedule of Changes in AOCI by Component Net of Tax) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	[1]			$ 12,664
Total other comprehensive income (loss)		$ 22	$ (115)	3	$ (85)
Ending balance		14,958		14,958
Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance	[2]			3,318
Total other comprehensive income (loss)		9	2	(7)	2
Ending balance		3,447		3,447
Total
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		(493)	(386)	(474)	(416)
Other comprehensive income before reclassifications: gains (losses)		60	(74)	142	(36)
Amounts reclassified from AOCI: (gains) losses	[3]	(38)	(41)	(139)	(49)
Total other comprehensive income (loss)		22	(115)	3	(85)
Ending balance		(471)	(501)	(471)	(501)
Total | Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		(115)	(86)	(99)	(86)
Other comprehensive income before reclassifications: gains (losses)		9	3	(6)	2
Amounts reclassified from AOCI: (gains) losses	[3]	0	(1)	(1)	0
Total other comprehensive income (loss)		9	2	(7)	2
Ending balance		(106)	(84)	(106)	(84)
Deferred Gains and Losses on Derivatives-Hedging Activities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		(241)	(146)	(176)	(178)
Other comprehensive income before reclassifications: gains (losses)		14	(7)	56	25
Amounts reclassified from AOCI: (gains) losses	[3]	(34)	(53)	(141)	(53)
Total other comprehensive income (loss)		(20)	(60)	(85)	(28)
Ending balance		(261)	(206)	(261)	(206)
Deferred Gains and Losses on Derivatives-Hedging Activities | Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		(34)	(22)	(17)	(20)
Other comprehensive income before reclassifications: gains (losses)		9	3	(6)	2
Amounts reclassified from AOCI: (gains) losses	[3]	(1)	(2)	(3)	(3)
Total other comprehensive income (loss)		8	1	(9)	(1)
Ending balance		(26)	(21)	(26)	(21)
Unrealized Gains and Losses on Investment Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		535	519	504	548
Other comprehensive income before reclassifications: gains (losses)		31	(59)	72	(55)
Amounts reclassified from AOCI: (gains) losses	[3]	(13)	(2)	(23)	(35)
Total other comprehensive income (loss)		18	(61)	49	(90)
Ending balance		553	458	553	458
Unrecognized Pension and Other Postretirement Benefit Costs
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		(781)	(754)	(797)	(782)
Other comprehensive income before reclassifications: gains (losses)		15	(9)	15	(6)
Amounts reclassified from AOCI: (gains) losses	[3]	9	14	25	39
Total other comprehensive income (loss)		24	5	40	33
Ending balance		(757)	(749)	(757)	(749)
Unrecognized Pension and Other Postretirement Benefit Costs | Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		(81)	(64)	(82)	(66)
Other comprehensive income before reclassifications: gains (losses)		0	0	0	0
Amounts reclassified from AOCI: (gains) losses	[3]	1	1	2	3
Total other comprehensive income (loss)		1	1	2	3
Ending balance		(80)	(63)	(80)	(63)
Other Comprehensive Income (Loss) From Equity Method Investee
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning balance		(6)	(5)	(5)	(4)
Other comprehensive income before reclassifications: gains (losses)		0	1	(1)	0
Amounts reclassified from AOCI: (gains) losses	[3]	0	0	0	0
Total other comprehensive income (loss)		0	1	(1)	0
Ending balance		$ (6)	$ (4)	$ (6)	$ (4)

[1] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[2] Dominion Gas’ Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[3] See table below for details about these reclassifications.

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Accumulated Other Comprehensive Income (Schedule of Reclassifications out of AOCI by Component Net of Tax) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating revenue		$ (3,132)	$ (2,971)	$ (8,651)	$ (9,127)
Purchased gas		77	85	252	446
Electric fuel and other energy-related purchases		606	636	1,791	2,180
Interest and related charges		250	230	715	674
Other income		(63)	(11)	(189)	(127)
Impairment		5	16	18	27
Income from operations including noncontrolling interests before income tax expense		(958)	(904)	(2,282)	(2,351)
Income tax expense		230	305	561	794
Other operations and maintenance		765	564	2,133	1,875
Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating revenue	[1]	(382)	(365)	(1,181)	(1,291)
Purchased gas	[1]	21	8	71	103
Interest and related charges		23	18	68	53
Other income		(7)	(4)	(22)	(17)
Income from operations including noncontrolling interests before income tax expense		(117)	(188)	(448)	(590)
Income tax expense		34	77	162	233
Deferred (gains) and losses on derivatives-hedging activities: | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Income from operations including noncontrolling interests before income tax expense		(55)	(83)	(229)	(87)
Income tax expense		21	30	88	34
Income from continuing operations including noncontrolling interests		(34)	(53)	(141)	(53)
Deferred (gains) and losses on derivatives-hedging activities: | Amounts Reclassified From AOCI | Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Income from operations including noncontrolling interests before income tax expense		(3)	(3)	(5)	(4)
Income tax expense		2	1	2	1
Income from continuing operations including noncontrolling interests		(1)	(2)	(3)	(3)
Deferred (gains) and losses on derivatives-hedging activities: | Commodity contracts | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating revenue		(64)	(87)	(266)	(103)
Purchased gas		1	2	9	9
Electric fuel and other energy-related purchases		1		8
Deferred (gains) and losses on derivatives-hedging activities: | Commodity contracts | Amounts Reclassified From AOCI | Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating revenue		(1)	(3)	(6)	(4)
Deferred (gains) and losses on derivatives-hedging activities: | Interest rate contracts | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Interest and related charges		10	2	21	7
Deferred (gains) and losses on derivatives-hedging activities: | Interest rate contracts | Amounts Reclassified From AOCI | Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Interest and related charges		1		2
Deferred (gains) and losses on derivatives-hedging activities: | Foreign currency | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other income		(3)		(1)
Deferred (gains) and losses on derivatives-hedging activities: | Foreign currency | Amounts Reclassified From AOCI | Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other income		(3)		(1)
Unrealized (gains) and losses on investment securities: | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Realized (gain) loss on sale of securities		(25)	(18)	(55)	(82)
Impairment		5	16	19	27
Income from operations including noncontrolling interests before income tax expense		(20)	(2)	(36)	(55)
Income tax expense		7	0	13	20
Income from continuing operations including noncontrolling interests		(13)	(2)	(23)	(35)
Unrecognized pension and other postretirement benefit costs:
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized pension and other postretirement benefit costs, before tax		13	21	41	64
Unrecognized pension and other postretirement benefit costs, income tax expense		(4)	(7)	(16)	(25)
Unrecognized pension and other postretirement benefit costs, net of tax		9	14	25	39
Unrecognized pension and other postretirement benefit costs: | Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrecognized pension and other postretirement benefit costs, before tax		2	2	4	6
Unrecognized pension and other postretirement benefit costs, income tax expense		(1)	(1)	(2)	(3)
Unrecognized pension and other postretirement benefit costs, net of tax		1	1	2	3
Prior service (credit) costs | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other operations and maintenance		(4)	(3)	(11)	(9)
Actuarial (gains) losses | Amounts Reclassified From AOCI
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other operations and maintenance		17	24	52	73
Actuarial (gains) losses | Amounts Reclassified From AOCI | Dominion Gas Holdings, LLC
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other operations and maintenance		$ 2	$ 2	$ 4	$ 6

[1] See Note 17 for amounts attributable to related parties.

XML

Fair Value Measurements (Fair Value, Option, Quantitative Disclosures) (Details) $ in Millions		9 Months Ended
		Sep. 30, 2016 USD ($) $ / MWh $ / MMBTU	Dec. 31, 2015 USD ($)
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 295	$ 388
Fair Value of Derivative Liabilities		422	343
Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		118	127
Fair Value of Derivative Liabilities		291	86
Dominion Gas Holdings, LLC
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		14	11
Fair Value of Derivative Liabilities		6	14
Level 3 | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		90
Fair Value, Measurements, Recurring | Physical and financial forwards and futures:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		268	364
Fair Value of Derivative Liabilities		111	160
Fair Value, Measurements, Recurring | Virginia Electric and Power Company | Physical and financial forwards and futures:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		116	114
Fair Value of Derivative Liabilities		24	27
Fair Value, Measurements, Recurring | Dominion Gas Holdings, LLC | Physical and financial forwards and futures:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		6	11
Fair Value of Derivative Liabilities		2
Fair Value, Measurements, Recurring | Level 3
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		96
Fair Value of Derivative Liabilities		7
Fair Value, Measurements, Recurring | Level 3 | Physical and financial forwards and futures:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		96	114
Fair Value of Derivative Liabilities		7	19
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | Natural Gas | Physical and financial forwards and futures:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets	[1]	85
Fair Value of Derivative Liabilities	[1]	$ 4
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | Natural Gas | Liabilities | Physical and financial forwards and futures: | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2]	(2)
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | Natural Gas | Liabilities | Physical and financial forwards and futures: | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2]	4
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | Natural Gas | Liabilities | Physical and financial forwards and futures: | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2],[3]	1
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | Natural Gas | Assets | Physical and financial forwards and futures: | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2]	(2)
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | Natural Gas | Assets | Physical and financial forwards and futures: | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2]	7
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | Natural Gas | Assets | Physical and financial forwards and futures: | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU		0
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | FTRs | Physical and financial forwards and futures:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 7
Fair Value of Derivative Liabilities		$ 2
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | FTRs | Liabilities | Physical and financial forwards and futures: | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[2]	(11)
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | FTRs | Liabilities | Physical and financial forwards and futures: | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[2]	6
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | FTRs | Liabilities | Physical and financial forwards and futures: | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[2],[3]	1
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | FTRs | Assets | Physical and financial forwards and futures: | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[2]	(6)
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | FTRs | Assets | Physical and financial forwards and futures: | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[2]	6
Fair Value, Measurements, Recurring | Level 3 | Discounted cash flow | FTRs | Assets | Physical and financial forwards and futures: | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[2],[3]	1
Fair Value, Measurements, Recurring | Level 3 | Option model | Natural Gas | Physical and financial options:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 4
Fair Value of Derivative Liabilities		$ 1
Fair Value, Measurements, Recurring | Level 3 | Option model | Natural Gas | Liabilities | Physical and financial options: | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2]	2
Price volatility percentage	[4]	30.00%
Fair Value, Measurements, Recurring | Level 3 | Option model | Natural Gas | Liabilities | Physical and financial options: | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2]	4
Price volatility percentage	[4]	46.00%
Fair Value, Measurements, Recurring | Level 3 | Option model | Natural Gas | Liabilities | Physical and financial options: | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2],[3]	3
Price volatility percentage	[3],[4]	38.00%
Fair Value, Measurements, Recurring | Level 3 | Option model | Natural Gas | Assets | Physical and financial options: | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2]	2
Price volatility percentage	[4]	19.00%
Fair Value, Measurements, Recurring | Level 3 | Option model | Natural Gas | Assets | Physical and financial options: | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2]	7
Price volatility percentage	[4]	46.00%
Fair Value, Measurements, Recurring | Level 3 | Option model | Natural Gas | Assets | Physical and financial options: | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[2],[3]	3
Price volatility percentage	[3],[4]	24.00%
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Liabilities		$ 2
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Physical and financial forwards and futures:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		90	101
Fair Value of Derivative Liabilities		2	8
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | Natural Gas | Physical and financial forwards and futures:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets	[5]	$ 81
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | Natural Gas | Assets | Physical and financial forwards and futures: | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[6]	(2)
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | Natural Gas | Assets | Physical and financial forwards and futures: | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[6]	7
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | Natural Gas | Assets | Physical and financial forwards and futures: | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[6],[7]	0
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | FTRs | Physical and financial forwards and futures:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 7
Fair Value of Derivative Liabilities		$ 2
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | FTRs | Liabilities | Physical and financial forwards and futures: | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[6]	(11)
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | FTRs | Liabilities | Physical and financial forwards and futures: | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[6]	6
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | FTRs | Liabilities | Physical and financial forwards and futures: | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[6],[7]	1
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | FTRs | Assets | Physical and financial forwards and futures: | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[6]	(6)
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | FTRs | Assets | Physical and financial forwards and futures: | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[6]	6
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Discounted cash flow | FTRs | Assets | Physical and financial forwards and futures: | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MWh	[6],[7]	1
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Option model | Natural Gas | Physical and financial options:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 2
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Option model | Natural Gas | Assets | Physical and financial options: | Minimum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[6]	2
Price volatility percentage	[8]	19.00%
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Option model | Natural Gas | Assets | Physical and financial options: | Maximum
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[6]	7
Price volatility percentage	[8]	33.00%
Fair Value, Measurements, Recurring | Level 3 | Virginia Electric and Power Company | Option model | Natural Gas | Assets | Physical and financial options: | Weighted Average
Fair Value, Option, Quantitative Disclosures [Line Items]
Market price (per Dth, per MWh) | $ / MMBTU	[6],[7]	3
Price volatility percentage	[7],[8]	24.00%
Fair Value, Measurements, Recurring | Level 3 | Dominion Gas Holdings, LLC | Physical and financial forwards and futures:
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value of Derivative Assets		$ 0	$ 6
Fair Value of Derivative Liabilities		$ 0

[1] Includes basis.

[2] Represents market prices beyond defined terms for Levels 1 and 2.

[3] Averages weighted by volume.

[4] Represents volatilities unrepresented in published markets.

[5] Includes basis.

[6] Represents market prices beyond defined terms for Levels 1 and 2.

[7] Averages weighted by volume.

[8] Represents volatilities unrepresented in published markets.

XML

Fair Value Measurements (Assets and Liabilities that are Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		$ 295	$ 388
Derivative Liabilities		422	343
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[1]	4,766	4,589
Total liabilities		422	343
Fair Value, Measurements, Recurring | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		268	364
Derivative Liabilities		111	160
Fair Value, Measurements, Recurring | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		19	24
Derivative Liabilities		307	183
Fair Value, Measurements, Recurring | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		8
Derivative Liabilities		4
Fair Value, Measurements, Recurring | Equity securities: | Large cap | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	2,712	2,547
Fair Value, Measurements, Recurring | Equity securities: | Large cap | Non-United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	10	10
Fair Value, Measurements, Recurring | Equity securities: | REIT | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	67	63
Fair Value, Measurements, Recurring | Equity securities: | Other | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	6	5
Fair Value, Measurements, Recurring | Fixed income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	518	437
Fair Value, Measurements, Recurring | Fixed income: | United States Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	669	659
Fair Value, Measurements, Recurring | Fixed income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	372	376
Fair Value, Measurements, Recurring | Fixed income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	109	100
Fair Value, Measurements, Recurring | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	8	4
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[1]	3,241	3,086
Total liabilities		0	0
Fair Value, Measurements, Recurring | Level 1 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0	1
Derivative Liabilities		0	0
Fair Value, Measurements, Recurring | Level 1 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liabilities		0	0
Fair Value, Measurements, Recurring | Level 1 | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liabilities		0
Fair Value, Measurements, Recurring | Level 1 | Equity securities: | Large cap | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	2,712	2,547
Fair Value, Measurements, Recurring | Level 1 | Equity securities: | Large cap | Non-United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	10	10
Fair Value, Measurements, Recurring | Level 1 | Equity securities: | REIT | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	67	63
Fair Value, Measurements, Recurring | Level 1 | Equity securities: | Other | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	6	5
Fair Value, Measurements, Recurring | Level 1 | Fixed income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 1 | Fixed income: | United States Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	438	458
Fair Value, Measurements, Recurring | Level 1 | Fixed income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 1 | Fixed income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 1 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	8	2
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[1]	1,429	1,389
Total liabilities		415	324
Fair Value, Measurements, Recurring | Level 2 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		172	249
Derivative Liabilities		104	141
Fair Value, Measurements, Recurring | Level 2 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		19	24
Derivative Liabilities		307	183
Fair Value, Measurements, Recurring | Level 2 | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		8
Derivative Liabilities		4
Fair Value, Measurements, Recurring | Level 2 | Equity securities: | Large cap | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 2 | Equity securities: | Large cap | Non-United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 2 | Equity securities: | REIT | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 2 | Equity securities: | Other | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 2 | Fixed income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	518	437
Fair Value, Measurements, Recurring | Level 2 | Fixed income: | United States Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	231	201
Fair Value, Measurements, Recurring | Level 2 | Fixed income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	372	376
Fair Value, Measurements, Recurring | Level 2 | Fixed income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	109	100
Fair Value, Measurements, Recurring | Level 2 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	2
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		96
Total assets	[1]	96	114
Derivative Liabilities		7
Total liabilities		7	19
Fair Value, Measurements, Recurring | Level 3 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		96	114
Derivative Liabilities		7	19
Fair Value, Measurements, Recurring | Level 3 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liabilities		0	0
Fair Value, Measurements, Recurring | Level 3 | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liabilities		0
Fair Value, Measurements, Recurring | Level 3 | Equity securities: | Large cap | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 3 | Equity securities: | Large cap | Non-United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 3 | Equity securities: | REIT | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 3 | Equity securities: | Other | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 3 | Fixed income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 3 | Fixed income: | United States Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 3 | Fixed income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 3 | Fixed income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Fair Value, Measurements, Recurring | Level 3 | Cash equivalents and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[1]	0	0
Virginia Electric and Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		118	127
Derivative Liabilities		291	86
Virginia Electric and Power Company | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		90
Virginia Electric and Power Company | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[2]	2,120	1,996
Total liabilities		291	86
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		116	114
Derivative Liabilities		24	27
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		2	13
Derivative Liabilities		267	59
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Equity securities: | Large cap | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	1,183	1,100
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Equity securities: | REIT | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	67	63
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Fixed income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	298	238
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Fixed income: | United States Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	251	259
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Fixed income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	174	175
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Fixed income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	29	34
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[2]	1,394	1,343
Total liabilities		0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liabilities		0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liabilities		0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Equity securities: | Large cap | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	1,183	1,100
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Equity securities: | REIT | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	67	63
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Fixed income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Fixed income: | United States Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	144	180
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Fixed income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 1 | Fixed income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[2]	636	552
Total liabilities		289	78
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		26	13
Derivative Liabilities		22	19
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		2	13
Derivative Liabilities		267	59
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Equity securities: | Large cap | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Equity securities: | REIT | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Fixed income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	298	238
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Fixed income: | United States Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	107	79
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Fixed income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	174	175
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 2 | Fixed income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	29	34
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[2]	90	101
Derivative Liabilities		2
Total liabilities		2	8
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		90	101
Derivative Liabilities		2	8
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liabilities		0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Equity securities: | Large cap | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Equity securities: | REIT | United States:
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Fixed income: | Corporate debt instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Fixed income: | United States Treasury securities and agency debentures
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Fixed income: | State and municipal
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Virginia Electric and Power Company | Fair Value, Measurements, Recurring | Level 3 | Fixed income: | Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	[2]	0	0
Dominion Gas Holdings, LLC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		14	11
Derivative Liabilities		6	14
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		14	11
Total liabilities		6	14
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		6	11
Derivative Liabilities		2
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities			14
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		8
Derivative Liabilities		4
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		0	0
Total liabilities		0	0
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 1 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liabilities		0
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 1 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities			0
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 1 | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liabilities		0
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		14	5
Total liabilities		6	14
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 2 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		6	5
Derivative Liabilities		2
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 2 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities			14
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 2 | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		8
Derivative Liabilities		4
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		0	6
Total liabilities		0	0
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 3 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0	6
Derivative Liabilities		0
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 3 | Interest rate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities			$ 0
Dominion Gas Holdings, LLC | Fair Value, Measurements, Recurring | Level 3 | Foreign currency
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liabilities		$ 0

[1] Includes investments held in the nuclear decommissioning and rabbi trusts.

[2] Includes investments held in the nuclear decommissioning and rabbi trusts.

XML

Fair Value Measurements (Net Change in the Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) - Commodity - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning balance	$ 124	$ 71	$ 95	$ 107
Total realized and unrealized gains (losses):
Included in earnings	(7)	(9)	(23)	1
Included in other comprehensive income (loss)	0	5	2	(7)
Included in regulatory assets/liabilities	(37)	47	(5)	18
Settlements	9	10	27	1
Transfers out of Level 3	0	(1)	(7)	3
Ending balance	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	0	1	0	1
Virginia Electric and Power Company
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning balance	125	73	93	102
Total realized and unrealized gains (losses):
Included in earnings	(7)	(10)	(24)	(1)
Included in regulatory assets/liabilities	(37)	47	(5)	18
Settlements	7	10	24	1
Ending balance	88	120	88	120
Dominion Gas Holdings, LLC
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning balance	0	(1)	6	2
Total realized and unrealized gains (losses):
Included in earnings	0	0	0	1
Included in other comprehensive income (loss)	0	5	2	(7)
Settlements	0	0	0	(1)
Transfers out of Level 3	0	0	(8)	9
Ending balance	$ 0	$ 4	$ 0	$ 4

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Fair Value Measurements (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized gains or losses included in earnings in Level 3 fair value category	$ 0	$ 0	$ 0	$ 0
Virginia Electric and Power Company
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized gains or losses included in earnings in Level 3 fair value category	0	0	0	0
Dominion Gas Holdings, LLC
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized gains or losses included in earnings in Level 3 fair value category	$ 0	$ 0	$ 0	$ 0

XML

Fair Value Measurements (Gains and Losses Included in Earnings in the Level 3 Fair Value Category) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) included in earnings	$ (7)	$ (9)	$ (23)	$ 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
Operating Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) included in earnings	0	0	0	2
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		0		1
Electric Fuel and Other Energy-Related Purchases
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) included in earnings	$ (7)	(9)	$ (23)	(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		$ 0

XML

Fair Value Measurements (Financial Instruments' Carrying Amounts and Fair Values) (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Valuation of certain fair value hedges		$ 14	$ 7
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	[1]	26,287	21,873
Junior subordinated notes	[2]	2,980	1,340
Remarketable subordinated notes	[2]	2,371	2,080
Estimate of Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	[1],[3]	29,077	23,210
Junior subordinated notes	[2],[3]	3,030	1,192
Remarketable subordinated notes	[2],[3]	2,392	2,129
Virginia Electric and Power Company | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	[2]	9,642	9,368
Virginia Electric and Power Company | Estimate of Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	[2],[3]	11,259	10,400
Dominion Gas Holdings, LLC | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	[4]	3,945	3,269
Dominion Gas Holdings, LLC | Estimate of Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	[3],[4]	$ 4,139	$ 3,299

[1] Carrying amount includes amounts which represent the unamortized debt issuance costs, discount and/or premium, and foreign currency remeasurement adjustments. At September 30, 2016 and December 31, 2015, includes the valuation of certain fair value hedges associated with fixed rate debt of $14 million and $7 million, respectively.

[2] Carrying amount includes amounts which represent the unamortized debt issuance costs, discount and/or premium.

[3] Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

[4] Carrying amount includes amounts which represent the unamortized debt issuance costs, discount and/or premium, and foreign currency remeasurement adjustments.

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Derivatives and Hedge Accounting Activities (Schedule of Offsetting Assets) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 288	$ 379
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	288	379
Total derivatives, not subject to a master netting or similar arrangement	7	9
Gross Amounts of Recognized Assets, Total	295	388
Derivative Asset	295	388
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	97	141
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	191	238
Commodity | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	173	217
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	173	217
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	20	37
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	153	180
Commodity | Exchange
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	88	138
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	88	138
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	63	82
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	25	56
Interest rate | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	19	24
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	19	24
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	10	22
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	9	2
Foreign currency | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	8	0
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	8	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	4	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	4	0
Virginia Electric and Power Company
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	90	114
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	90	114
Total derivatives, not subject to a master netting or similar arrangement	28	13
Gross Amounts of Recognized Assets, Total	118	127
Derivative Asset	118	127
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	2	13
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	88	101
Virginia Electric and Power Company | Commodity | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	88	101
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	88	101
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	2	3
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	86	98
Virginia Electric and Power Company | Interest rate | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	2	13
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	2	13
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	0	10
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	2	3
Dominion Gas Holdings, LLC
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	14	11
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	14	11
Derivative Asset	14	11
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	5	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	9	11
Dominion Gas Holdings, LLC | Commodity | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	6	11
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	6	11
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	1	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	5	11
Dominion Gas Holdings, LLC | Foreign currency | Over-the-counter
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	8	0
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Assets Presented in the Consolidated Balance Sheet	8	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	4	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral Received	0	0
Net Amounts	$ 4	$ 0

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Derivatives and Hedge Accounting Activities (Schedule of Offsetting Liabilities) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 417	$ 335
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	417	335
Total derivatives, not subject to a master netting or similar arrangement	5	8
Gross Amounts of Recognized Liabilities, Total	422	343
Derivative Liabilities	422	343
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	97	141
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	320	194
Commodity | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	43	70
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	43	70
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	20	37
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	23	33
Commodity | Exchange
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	63	82
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	63	82
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	63	82
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	0	0
Interest rate | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	307	183
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	307	183
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	10	22
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	297	161
Foreign currency | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	4	0
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	4	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	4	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	0	0
Virginia Electric and Power Company
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	276	64
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	276	64
Total derivatives, not subject to a master netting or similar arrangement	15	22
Gross Amounts of Recognized Liabilities, Total	291	86
Derivative Liabilities	291	86
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	2	13
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	274	51
Virginia Electric and Power Company | Commodity | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	9	5
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	9	5
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	2	3
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	7	2
Virginia Electric and Power Company | Interest rate | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	267	59
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	267	59
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	0	10
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	267	49
Dominion Gas Holdings, LLC
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	6	14
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	6	14
Derivative Liabilities	6	14
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	5	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	1	14
Dominion Gas Holdings, LLC | Commodity | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	2	0
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	2	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	1	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	1	0
Dominion Gas Holdings, LLC | Interest rate | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	0	14
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	0	14
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	0	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	0	14
Dominion Gas Holdings, LLC | Foreign currency | Over-the-counter
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	4	0
Gross Amounts Offset in the Consolidated Balance Sheet	0	0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	4	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Financial Instruments	4	0
Gross Amounts Not Offset in the Consolidated Balance Sheet, Cash Collateral	0	0
Net Amounts	$ 0	$ 0

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Derivatives and Hedge Accounting Activities (Volume of Derivative Activity) (Details) - 9 months ended Sep. 30, 2016 MMcf in Thousands, € in Millions, $ in Millions		USD ($) MWh MMcf gal	EUR (€)
Fixed Price - Natural Gas - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)	[1]	104
Fixed Price - Natural Gas - Non-current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)	[1]	23
Basis - Natural Gas - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)		261
Basis - Natural Gas - Non-current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)		626
Fixed Price - Electricity - Current Derivative Contract
Derivative [Line Items]
Volume of electricity (MWh) | MWh		8,274,639
Fixed Price - Electricity - Non-current Derivative Contract
Derivative [Line Items]
Volume of electricity (MWh) | MWh		659,440
Financial Transmission Rights - Electricity- Current Derivative Contract
Derivative [Line Items]
Volume of electricity (MWh) | MWh		72,352,190
Financial Transmission Rights - Electricity- Non-current Derivative Contract
Derivative [Line Items]
Volume of electricity (MWh) | MWh		0
Liquids - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal) | gal	[2]	39,269,554
Liquids - Non-current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal) | gal	[2]	0
Foreign currency
Derivative [Line Items]
Interest rate (US Dollars, Euros) | €			€ 250
Foreign Exchange - Current Derivative Contract
Derivative [Line Items]
Interest rate (US Dollars, Euros) | $	[3],[4]	$ 0
Foreign Exchange - Non- Current Derivative Contract
Derivative [Line Items]
Interest rate (US Dollars, Euros) | $	[3],[4]	280
Interest Rate - Current Derivative Contract
Derivative [Line Items]
Interest rate (US Dollars, Euros) | $	[4]	2,200
Interest Rate - Non-current Derivative Contract
Derivative [Line Items]
Interest rate (US Dollars, Euros) | $	[4]	$ 1,600
Virginia Electric and Power Company | Fixed Price - Natural Gas - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)	[5]	32
Virginia Electric and Power Company | Fixed Price - Natural Gas - Non-current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)	[5]	12
Virginia Electric and Power Company | Basis - Natural Gas - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)		126
Virginia Electric and Power Company | Basis - Natural Gas - Non-current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)		558
Virginia Electric and Power Company | Financial Transmission Rights - Electricity- Current Derivative Contract
Derivative [Line Items]
Volume of electricity (MWh) | MWh		70,978,901
Virginia Electric and Power Company | Financial Transmission Rights - Electricity- Non-current Derivative Contract
Derivative [Line Items]
Volume of electricity (MWh) | MWh		0
Virginia Electric and Power Company | Interest Rate - Current Derivative Contract
Derivative [Line Items]
Interest rate (US Dollars, Euros) | $		$ 1,200
Virginia Electric and Power Company | Interest Rate - Non-current Derivative Contract
Derivative [Line Items]
Interest rate (US Dollars, Euros) | $		$ 600
Dominion Gas Holdings, LLC | Fixed Price - Natural Gas - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)		6
Dominion Gas Holdings, LLC | Fixed Price - Natural Gas - Non-current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)		0
Dominion Gas Holdings, LLC | Basis - Natural Gas - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)		6
Dominion Gas Holdings, LLC | Basis - Natural Gas - Non-current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal)		0
Dominion Gas Holdings, LLC | Liquids - Current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal) | gal		33,095,554
Dominion Gas Holdings, LLC | Liquids - Non-current Derivative Contract
Derivative [Line Items]
Volume of derivative activity (bcf, Gal) | gal		0
Dominion Gas Holdings, LLC | Foreign currency
Derivative [Line Items]
Interest rate (US Dollars, Euros) | €			€ 250
Dominion Gas Holdings, LLC | Foreign Exchange - Current Derivative Contract
Derivative [Line Items]
Interest rate (US Dollars, Euros) | $	[6]	$ 0
Dominion Gas Holdings, LLC | Foreign Exchange - Non- Current Derivative Contract
Derivative [Line Items]
Interest rate (US Dollars, Euros) | $	[6]	$ 280

[1] Includes options.

[2] Includes NGLs and oil.

[3] Euro equivalent volumes are €250,000,000.

[4] Maturity is determined based on final settlement period.

[5] Includes options.

[6] Maturity is determined based on final settlement period. Euro equivalent volumes are €250,000,000.

XML

Derivatives and Hedge Accounting Activities (Selected Information Related to Gains (Losses) on Cash Flow Hedges Included in AOCI) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ (261)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	13
Commodity | Gas Energy Contract
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	(2)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (2)
Maximum Term	39 months
Commodity | Electricity Energy Contract
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ 44
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ 42
Maximum Term	15 months
Commodity | Other Energy Contract
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ (1)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (1)
Maximum Term	6 months
Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ (304)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (26)
Maximum Term	378 months
Foreign currency
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ 2
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ 0
Maximum Term	117 months
Virginia Electric and Power Company
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ (22)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	(1)
Virginia Electric and Power Company | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	(22)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (1)
Maximum Term	378 months
Dominion Gas Holdings, LLC
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ (26)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	(3)
Dominion Gas Holdings, LLC | Commodity | NGLs
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	(1)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (1)
Maximum Term	6 months
Dominion Gas Holdings, LLC | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ (27)
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ (2)
Maximum Term	339 months
Dominion Gas Holdings, LLC | Foreign currency
Derivative Instruments, Gain (Loss) [Line Items]
AOCI After-Tax	$ 2
Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax	$ 0
Maximum Term	117 months

XML

Derivatives and Hedge Accounting Activities (Fair Value of Derivatives) (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset		$ 295	$ 388
Derivative Liabilities		422	343
Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	173	255
Current Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		164	252
Current Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset		9	3
Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	122	133
Noncurrent Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		104	112
Noncurrent Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset		10	21
Noncurrent Assets | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Asset		8
Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[3]	286	312
Current Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		100	148
Current Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		182	164
Current Liabilities | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Liabilities		4
Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[4]	136	31
Noncurrent Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		11	12
Noncurrent Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		125	19
Fair Value – Derivatives under Hedge Accounting
Derivatives, Fair Value [Line Items]
Derivative Asset		90	128
Derivative Liabilities		334	215
Fair Value – Derivatives under Hedge Accounting | Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	68	104
Fair Value – Derivatives under Hedge Accounting | Current Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		59	101
Fair Value – Derivatives under Hedge Accounting | Current Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset		9	3
Fair Value – Derivatives under Hedge Accounting | Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	22	24
Fair Value – Derivatives under Hedge Accounting | Noncurrent Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		4	3
Fair Value – Derivatives under Hedge Accounting | Noncurrent Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset		10	21
Fair Value – Derivatives under Hedge Accounting | Noncurrent Assets | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Asset		8
Fair Value – Derivatives under Hedge Accounting | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[3]	208	196
Fair Value – Derivatives under Hedge Accounting | Current Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		22	32
Fair Value – Derivatives under Hedge Accounting | Current Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		182	164
Fair Value – Derivatives under Hedge Accounting | Current Liabilities | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Liabilities		4
Fair Value – Derivatives under Hedge Accounting | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[4]	126	19
Fair Value – Derivatives under Hedge Accounting | Noncurrent Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		1	0
Fair Value – Derivatives under Hedge Accounting | Noncurrent Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		125	19
Fair Value – Derivatives not under Hedge Accounting
Derivatives, Fair Value [Line Items]
Derivative Asset		205	260
Derivative Liabilities		88	128
Fair Value – Derivatives not under Hedge Accounting | Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[1]	105	151
Fair Value – Derivatives not under Hedge Accounting | Current Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		105	151
Fair Value – Derivatives not under Hedge Accounting | Current Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset		0	0
Fair Value – Derivatives not under Hedge Accounting | Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[2]	100	109
Fair Value – Derivatives not under Hedge Accounting | Noncurrent Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		100	109
Fair Value – Derivatives not under Hedge Accounting | Noncurrent Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset		0	0
Fair Value – Derivatives not under Hedge Accounting | Noncurrent Assets | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Asset		0
Fair Value – Derivatives not under Hedge Accounting | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[3]	78	116
Fair Value – Derivatives not under Hedge Accounting | Current Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		78	116
Fair Value – Derivatives not under Hedge Accounting | Current Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		0	0
Fair Value – Derivatives not under Hedge Accounting | Current Liabilities | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Liabilities		0
Fair Value – Derivatives not under Hedge Accounting | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[4]	10	12
Fair Value – Derivatives not under Hedge Accounting | Noncurrent Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		10	12
Fair Value – Derivatives not under Hedge Accounting | Noncurrent Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		0	0
Virginia Electric and Power Company
Derivatives, Fair Value [Line Items]
Derivative Asset		118	127
Derivative Liabilities		291	86
Virginia Electric and Power Company | Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[5]	27	18
Virginia Electric and Power Company | Current Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		25	18
Virginia Electric and Power Company | Current Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset		2
Virginia Electric and Power Company | Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[6]	91	109
Virginia Electric and Power Company | Noncurrent Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		91	96
Virginia Electric and Power Company | Noncurrent Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset			13
Virginia Electric and Power Company | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[7]	161	80
Virginia Electric and Power Company | Current Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		19	23
Virginia Electric and Power Company | Current Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		142	57
Virginia Electric and Power Company | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[8]	130	6
Virginia Electric and Power Company | Noncurrent Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		5	4
Virginia Electric and Power Company | Noncurrent Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		125	2
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting
Derivatives, Fair Value [Line Items]
Derivative Asset		2	13
Derivative Liabilities		267	59
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[5]	2	0
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Current Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		0	0
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Current Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset		2
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[6]	0	13
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Noncurrent Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		0	0
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Noncurrent Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset			13
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[7]	142	57
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Current Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		0	0
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Current Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		142	57
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[8]	125	2
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Noncurrent Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		0	0
Virginia Electric and Power Company | Fair Value – Derivatives under Hedge Accounting | Noncurrent Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		125	2
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting
Derivatives, Fair Value [Line Items]
Derivative Asset		116	114
Derivative Liabilities		24	27
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[5]	25	18
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Current Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		25	18
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Current Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset		0
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[6]	91	96
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		91	96
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Assets | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Asset			0
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[7]	19	23
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Current Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		19	23
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Current Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		0	0
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[8]	5	4
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		5	4
Virginia Electric and Power Company | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities		0	0
Dominion Gas Holdings, LLC
Derivatives, Fair Value [Line Items]
Derivative Asset		14	11
Derivative Liabilities		6	14
Dominion Gas Holdings, LLC | Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[9]	6	10
Dominion Gas Holdings, LLC | Current Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		6	10
Dominion Gas Holdings, LLC | Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[10]	8	1
Dominion Gas Holdings, LLC | Noncurrent Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset			1
Dominion Gas Holdings, LLC | Noncurrent Assets | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Asset		8
Dominion Gas Holdings, LLC | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[11]	6
Dominion Gas Holdings, LLC | Current Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		2
Dominion Gas Holdings, LLC | Current Liabilities | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Liabilities		4
Dominion Gas Holdings, LLC | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[12]		14
Dominion Gas Holdings, LLC | Noncurrent Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities			14
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting
Derivatives, Fair Value [Line Items]
Derivative Asset		9	11
Derivative Liabilities		6	14
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting | Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[9]	1	10
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting | Current Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		1	10
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting | Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[10]	8	1
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting | Noncurrent Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset			1
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting | Noncurrent Assets | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Asset		8
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[11]	6
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting | Current Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		2
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting | Current Liabilities | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Liabilities		4
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[12]		14
Dominion Gas Holdings, LLC | Fair Value – Derivatives under Hedge Accounting | Noncurrent Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities			14
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting
Derivatives, Fair Value [Line Items]
Derivative Asset		5	0
Derivative Liabilities		0	0
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting | Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[9]	5	0
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting | Current Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset		5	0
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset	[10]	0	0
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Assets | Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset			0
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Assets | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Asset		0
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting | Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[11]	0
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting | Current Liabilities | Commodity
Derivatives, Fair Value [Line Items]
Derivative Liabilities		0
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting | Current Liabilities | Foreign currency
Derivatives, Fair Value [Line Items]
Derivative Liabilities		$ 0
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liabilities	[12]		0
Dominion Gas Holdings, LLC | Fair Value – Derivatives not under Hedge Accounting | Noncurrent Liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Derivative Liabilities			$ 0

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

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

[3] Current derivative liabilities are presented in other current liabilities in Dominion's Consolidated Balance Sheets.

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

[5] Current derivative assets are presented in other current assets in Virginia Power's Consolidated Balance Sheets.

[6] Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Power's Consolidated Balance Sheets.

[7] Current derivative liabilities are presented in other current liabilities in Virginia Power's Consolidated Balance Sheets.

[8] Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheets.

[9] Current derivative assets are presented in other current assets in Dominion Gas' Consolidated Balance Sheets.

[10] Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Gas’ Consolidated Balance Sheets.

[11] Current derivative liabilities are presented in other current liabilities in Dominion Gas' Consolidated Balance Sheets.

[12] Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Gas’ Consolidated Balance Sheets.

XML

Derivatives and Hedge Accounting Activities (Gains and Losses on Derivatives in Cash Flow Hedging Relationships) (Details) - Cash Flow Hedges - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[1]	$ 22	$ (7)	$ 90	$ 45
Amount of Gain (Loss) Reclassified From AOCI to Income		55	83	229	87
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[2]	(16)	(69)	(258)	(24)
Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[1]	7	64	193	117
Amount of Gain (Loss) Reclassified From AOCI to Income		62	85	249	94
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[2]	0	0	0	3
Commodity | Operating revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified From AOCI to Income		64	87	266	103
Commodity | Purchased Gas
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified From AOCI to Income		(1)	(2)	(9)	(9)
Commodity | Electric Fuel and Other Energy-Related Purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified From AOCI to Income		(1)		(8)
Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[1],[3]	3	(71)	(107)	(72)
Amount of Gain (Loss) Reclassified From AOCI to Income	[3]	(10)	(2)	(21)	(7)
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[2],[3]	(16)	(69)	(258)	(27)
Foreign currency
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[1],[4]	12		4
Amount of Gain (Loss) Reclassified From AOCI to Income	[4]	3		1
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[2],[4]	0		0
Virginia Electric and Power Company
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[5]	(2)	(9)	(26)	(4)
Amount of Gain (Loss) Reclassified From AOCI to Income		0	0	(1)	(1)
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[6]	(16)	(69)	(258)	(24)
Virginia Electric and Power Company | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[5]				0
Amount of Gain (Loss) Reclassified From AOCI to Income					(1)
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[6]				3
Virginia Electric and Power Company | Commodity | Electric Fuel and Other Energy-Related Purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified From AOCI to Income					(1)
Virginia Electric and Power Company | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[5],[7]	(2)	(9)	(26)	(4)
Amount of Gain (Loss) Reclassified From AOCI to Income	[7]	0	0	(1)	0
Increase (Decrease) in Derivatives Subject to Regulatory Treatment	[6],[7]	(16)	(69)	(258)	(27)
Dominion Gas Holdings, LLC
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[8]	12	4	(11)	2
Amount of Gain (Loss) Reclassified From AOCI to Income		3	3	5	4
Dominion Gas Holdings, LLC | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[8]	0	11	(7)	10
Amount of Gain (Loss) Reclassified From AOCI to Income		1	3	6	4
Dominion Gas Holdings, LLC | Commodity | Operating revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified From AOCI to Income		1	3	6	4
Dominion Gas Holdings, LLC | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[8],[9]	0	(7)	(8)	(8)
Amount of Gain (Loss) Reclassified From AOCI to Income	[9]	(1)	$ 0	(2)	$ 0
Dominion Gas Holdings, LLC | Foreign currency
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)	[8],[10]	12		4
Amount of Gain (Loss) Reclassified From AOCI to Income	[10]	$ 3		$ 1

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

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

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

[4] Amounts recorded in Dominion’s Consolidated Statements of Income are classified in other income.

[5] Amounts deferred into AOCI have no associated effect in Virginia Power’s Consolidated Statements of Income.

[6] Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.

[7] Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges.

[8] Amounts deferred into AOCI have no associated effect in Dominion Gas' Consolidated Statements of Income.

[9] Amounts recorded in Dominion Gas' Consolidated Statements of Income are classified in interest and related charges.

[10] Amounts recorded in Dominion Gas' Consolidated Statements of Income are classified in other income.

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Derivatives and Hedge Accounting Activities (Schedule of Derivatives not Designated as Hedging Instruments) (Details) - Derivatives Not Designated as Hedging Instruments - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	$ (8)	$ (6)	$ (38)	$ 12
Commodity | Operating revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	25	2	19	20
Commodity | Purchased gas
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	(21)	(3)	(14)	(12)
Commodity | Electric fuel and other energy-related purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1]	(12)	(4)	(43)	5
Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[1],[2]	0	(1)	0	(1)
Virginia Electric and Power Company
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[3]	(10)	(6)	(40)	6
Virginia Electric and Power Company | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	[3],[4]	(10)	(6)	(40)	6
Dominion Gas Holdings, LLC | Commodity
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives		5	1	3	5
Dominion Gas Holdings, LLC | Commodity | Operating revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives		$ 5	$ 1	$ 3	$ 5

[1] Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income.

[2] Amounts recorded in Dominion's Consolidated Statements of Income are classified in interest and related charges.

[3] Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.

[4] Amounts recorded in Virginia Power's Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.

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Investments (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		9 Months Ended
	Oct. 31, 2016	May 31, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Gain (Loss) on Investments [Line Items]
Investment in equity method affiliates			$ 1,498		$ 1,320	[1]
Atlantic Coast Pipeline | Subsequent Event
Gain (Loss) on Investments [Line Items]
Membership interest percentage purchased	3.00%
Membership interest purchased	$ 14
Membership interest percentage	48.00%
Duke | Atlantic Coast Pipeline | Subsequent Event
Gain (Loss) on Investments [Line Items]
Membership interest percentage	47.00%
Dominion Gas Holdings, LLC | Iroquois | Partnership Interest
Gain (Loss) on Investments [Line Items]
Equity in earnings on investments			14	$ 17
Distributions received from investment			17	$ 26
Investment in equity method affiliates			97		102
Carrying amount of investment that exceeded share of underlying equity			8		8
Percentage of non-controlling interests sold		0.65%
Sales price		$ 7
Gain on sale of interests		5
After tax gain on sale of interests		$ 3
Categories of Investments, Marketable Securities, Trading Securities
Gain (Loss) on Investments [Line Items]
Assets Held-in-trust			$ 103		$ 100

[1] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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Investments (Marketable Equity and Debt Securities and Cash Equivalents (Classified as Available-for-sale) and Cost Method Investments in Decommissioning Trust Funds) (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Investment Holdings [Line Items]
Amortized Cost, Total		$ 3,034	$ 2,936
Total Unrealized Gains	[1]	1,394	1,258
Total Unrealized Losses	[1],[2]	(1)	(11)
Fair Value		4,427	4,183	[3]
Net assets related to pending sales and purchases of securities		9	12
Fair value of securities in an unrealized loss position		156	592
Cost method investments
Investment Holdings [Line Items]
Amortized Cost, Other Investments		69	70
Total Unrealized Gains	[1]	0	0
Total Unrealized Losses	[1]	0	0
Fair Value		69	70
Cash equivalents and other
Investment Holdings [Line Items]
Amortized Cost, Other Investments	[4]	12	14
Total Unrealized Gains	[1],[4]	0	0
Total Unrealized Losses	[1],[4]	0	0
Fair Value	[4]	12	14
Equity securities | Large cap | United States:
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		1,361	1,295
Total Unrealized Gains	[1]	1,312	1,213
Total Unrealized Losses	[1]	0	0
Fair Value		2,673	2,508
Equity securities | REIT
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		59	59
Total Unrealized Gains	[1]	8	4
Total Unrealized Losses	[1]	0	0
Fair Value		67	63
Corporate bonds
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		493	433
Total Unrealized Gains	[1]	26	11
Total Unrealized Losses	[1]	(1)	(7)
Fair Value		518	437
United States Treasury securities and agency debentures
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		645	654
Total Unrealized Gains	[1]	21	8
Total Unrealized Losses	[1]	0	(4)
Fair Value		666	658
State and municipal
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		306	312
Total Unrealized Gains	[1]	27	22
Total Unrealized Losses	[1]	0	0
Fair Value		333	334
Other
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		89	99
Total Unrealized Gains	[1]	0	0
Total Unrealized Losses	[1]	0	0
Fair Value		89	99
Virginia Electric and Power Company
Investment Holdings [Line Items]
Amortized Cost, Total		1,457	1,404
Total Unrealized Gains	[5]	617	548
Total Unrealized Losses	[5],[6]	0	(7)
Fair Value		2,074	1,945	[7]
Net assets related to pending sales and purchases of securities		4	8
Fair value of securities in an unrealized loss position		91	281
Virginia Electric and Power Company | Cost method investments
Investment Holdings [Line Items]
Amortized Cost, Other Investments		69	70
Total Unrealized Gains	[5]	0	0
Total Unrealized Losses	[5]	0	0
Fair Value		69	70
Virginia Electric and Power Company | Cash equivalents and other
Investment Holdings [Line Items]
Amortized Cost, Other Investments	[8]	5	8
Total Unrealized Gains	[5],[8]	0	0
Total Unrealized Losses	[5],[8]	0	0
Fair Value	[8]	5	8
Virginia Electric and Power Company | Equity securities | Large cap | United States:
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		606	574
Total Unrealized Gains	[5]	576	525
Total Unrealized Losses	[5]	0	0
Fair Value		1,182	1,099
Virginia Electric and Power Company | Equity securities | REIT
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		59	59
Total Unrealized Gains	[5]	8	4
Total Unrealized Losses	[5]	0	0
Fair Value		67	63
Virginia Electric and Power Company | Corporate bonds
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		285	237
Total Unrealized Gains	[5]	13	5
Total Unrealized Losses	[5]	0	(4)
Fair Value		298	238
Virginia Electric and Power Company | United States Treasury securities and agency debentures
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		246	260
Total Unrealized Gains	[5]	5	1
Total Unrealized Losses	[5]	0	(2)
Fair Value		251	259
Virginia Electric and Power Company | State and municipal
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		158	162
Total Unrealized Gains	[5]	15	13
Total Unrealized Losses	[5]	0	(1)
Fair Value		173	174
Virginia Electric and Power Company | Other
Investment Holdings [Line Items]
Amortized Cost, Marketable Securities		29	34
Total Unrealized Gains	[5]	0	0
Total Unrealized Losses	[5]	0	0
Fair Value		$ 29	$ 34

[1] Included in AOCI and the nuclear decommissioning trust regulatory liability.

[2] The fair value of securities in an unrealized loss position was $156 million and $592 million at September 30, 2016 and December 31, 2015, respectively.

[3] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[4] Includes pending sales of securities of $9 million and $12 million at September 30, 2016 and December 31, 2015, respectively.

[5] Included in AOCI and the nuclear decommissioning trust regulatory liability.

[6] The fair value of securities in an unrealized loss position was $91 million and $281 million at September 30, 2016 and December 31, 2015, respectively.

[7] Virginia Power’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[8] Includes pending sales of securities of $4 million and $8 million at September 30, 2016 and December 31, 2015, respectively.

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Investments (Fair Value of our Marketable Debt Securities by Contractual Maturity) (Details) $ in Millions	Sep. 30, 2016 USD ($)
Schedule of Held-to-maturity Securities [Line Items]
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
Virginia Electric and Power Company
Schedule of Held-to-maturity Securities [Line Items]
Due in one year or less	51
Due after one year through five years	228
Due after five years through ten years	202
Due after ten years	270
Total	$ 751

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Investments (Selected Information Regarding Marketable Equity and Debt Securities) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Available-for-sale securities:
Proceeds from sales		$ 300	$ 357	$ 1,009	$ 937
Realized gains	[1]	40	65	102	165
Realized losses	[1]	9	40	43	69
Virginia Electric and Power Company
Available-for-sale securities:
Proceeds from sales		131	198	478	407
Realized gains	[2]	18	45	48	82
Realized losses	[2]	$ 4	$ 18	$ 21	$ 33

[1] Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability.

[2] Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability.

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Investments (Recorded Other-Than-Temporary Impairment Losses on Investments) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Investments, Debt and Equity Securities [Abstract]
Total other-than-temporary impairment losses	[1]	$ 9	$ 29	$ 34	$ 55
Losses recorded to the nuclear decommissioning trust regulatory liability		(4)	(10)	(15)	(21)
Losses recognized in other comprehensive income (before taxes)		0	(3)	(1)	(7)
Impairment		5	16	18	27
Other than temporary impairment losses for debt securities (less than $1 million for the three months ended September 30, 2016)		$ 1	$ 3	$ 2	$ 7

[1] Amounts include other-than-temporary impairment losses for debt securities of less than $1 million and $3 million for the three months ended September 30, 2016 and 2015, respectively, and $2 million and $7 million for the nine months ended September 30, 2016 and 2015, respectively.

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Regulatory Assets and Liabilities (Schedule of Regulatory Assets) (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Regulatory assets current	[1]	$ 250	$ 351
Regulatory assets-non-current		2,143	1,865	[2]
Total regulatory assets		2,393	2,216
Deferred rate adjustment clause costs
Regulatory Assets [Line Items]
Regulatory assets current	[3]	101	90
Regulatory assets-non-current	[3]	271	295
Deferred nuclear refueling outage costs
Regulatory Assets [Line Items]
Regulatory assets current	[4]	$ 60	75
Deferred nuclear refueling outage costs | Maximum
Regulatory Assets [Line Items]
Amortization period for deferred costs		18 months
Deferred cost of fuel used in electric generation
Regulatory Assets [Line Items]
Regulatory assets current	[5]	$ 3	111
Other
Regulatory Assets [Line Items]
Regulatory assets current		86	75
Regulatory assets-non-current		203	127
Unrecognized pension and other postretirement benefit costs
Regulatory Assets [Line Items]
Regulatory assets-non-current	[6]	981	1,015
Derivatives
Regulatory Assets [Line Items]
Regulatory assets-non-current	[7]	366	110
PJM transmission rates
Regulatory Assets [Line Items]
Regulatory assets-non-current	[8]	192	192
Income taxes recoverable through future rates
Regulatory Assets [Line Items]
Regulatory assets-non-current	[9]	130	126
Virginia Electric and Power Company
Regulatory Assets [Line Items]
Regulatory assets current		197	326	[10]
Regulatory assets-non-current		897	667	[10]
Total regulatory assets		1,094	993
Virginia Electric and Power Company | Deferred rate adjustment clause costs
Regulatory Assets [Line Items]
Regulatory assets current	[3]	85	80
Regulatory assets-non-current	[3]	176	213
Virginia Electric and Power Company | Deferred nuclear refueling outage costs
Regulatory Assets [Line Items]
Regulatory assets current	[4]	60	75
Virginia Electric and Power Company | Deferred cost of fuel used in electric generation
Regulatory Assets [Line Items]
Regulatory assets current	[5]	3	111
Virginia Electric and Power Company | Other
Regulatory Assets [Line Items]
Regulatory assets current		49	60
Regulatory assets-non-current		64	55
Virginia Electric and Power Company | Derivatives
Regulatory Assets [Line Items]
Regulatory assets-non-current	[7]	366	110
Virginia Electric and Power Company | PJM transmission rates
Regulatory Assets [Line Items]
Regulatory assets-non-current	[8]	192	192
Virginia Electric and Power Company | Income taxes recoverable through future rates
Regulatory Assets [Line Items]
Regulatory assets-non-current	[9]	99	97
Dominion Gas Holdings, LLC
Regulatory Assets [Line Items]
Regulatory assets current	[1]	22	23
Regulatory assets-non-current	[11]	469	449
Total regulatory assets		491	472
Dominion Gas Holdings, LLC | Deferred rate adjustment clause costs
Regulatory Assets [Line Items]
Regulatory assets current	[3]	16	10
Regulatory assets-non-current	[3]	91	82
Dominion Gas Holdings, LLC | Other
Regulatory Assets [Line Items]
Regulatory assets current		6	13
Regulatory assets-non-current		82	65
Dominion Gas Holdings, LLC | Unrecognized pension and other postretirement benefit costs
Regulatory Assets [Line Items]
Regulatory assets-non-current	[6]	275	282
Dominion Gas Holdings, LLC | Income taxes recoverable through future rates
Regulatory Assets [Line Items]
Regulatory assets-non-current	[9]	$ 21	$ 20

[1] Current regulatory assets are presented in other current assets in Dominion's and Dominion Gas' Consolidated Balance Sheets.

[2] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

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

[4] 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.

[5] Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Dominion's and Virginia Power's generation operations. See Note 12 for more information.

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

[7] 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.

[8] Reflects amounts related to PJM transmission cost allocation matter. See Note 12 for more information.

[9] 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.

[10] Virginia Power’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[11] Noncurrent regulatory assets are presented in other deferred charges and other assets in Dominion Gas' Consolidated Balance Sheets

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Regulatory Assets and Liabilities (Schedule of Regulatory Liabilities) (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[1]	$ 124	$ 100
Regulatory liabilities-non-current		2,597	2,285	[2]
Total regulatory liabilities		2,721	2,385
Deferred cost of fuel used in electric generation
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[3]	62	0
Regulatory liabilities-non-current	[3]	27	97
PIPP
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[4]	26	46
Other
Regulatory Liabilities [Line Items]
Regulatory liabilities-current		36	54
Regulatory liabilities-non-current		200	185
Provision for future cost of removal and AROs
Regulatory Liabilities [Line Items]
Regulatory liabilities-non-current	[5]	1,412	1,120
Derivatives
Regulatory Liabilities [Line Items]
Regulatory liabilities-non-current	[6]	76	79
Nuclear decommissioning trust
Regulatory Liabilities [Line Items]
Regulatory liabilities-non-current	[7]	882	804
Virginia Electric and Power Company
Regulatory Liabilities [Line Items]
Regulatory liabilities-current		75	35	[8]
Regulatory liabilities-non-current		1,967	1,929	[8]
Total regulatory liabilities		2,042	1,964
Virginia Electric and Power Company | Deferred cost of fuel used in electric generation
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[3]	62	0
Regulatory liabilities-non-current	[3]	27	97
Virginia Electric and Power Company | Other
Regulatory Liabilities [Line Items]
Regulatory liabilities-current		13	35
Regulatory liabilities-non-current		50	59
Virginia Electric and Power Company | Provision for future cost of removal
Regulatory Liabilities [Line Items]
Regulatory liabilities-non-current	[5]	932	890
Virginia Electric and Power Company | Derivatives
Regulatory Liabilities [Line Items]
Regulatory liabilities-non-current	[6]	76	79
Virginia Electric and Power Company | Nuclear decommissioning trust
Regulatory Liabilities [Line Items]
Regulatory liabilities-non-current	[7]	882	804
Dominion Gas Holdings, LLC
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[1]	39	55
Regulatory liabilities-non-current	[9]	217	201
Total regulatory liabilities		256	256
Dominion Gas Holdings, LLC | PIPP
Regulatory Liabilities [Line Items]
Regulatory liabilities-current	[4]	26	46
Dominion Gas Holdings, LLC | Other
Regulatory Liabilities [Line Items]
Regulatory liabilities-current		13	9
Regulatory liabilities-non-current		44	31
Dominion Gas Holdings, LLC | Provision for future cost of removal and AROs
Regulatory Liabilities [Line Items]
Regulatory liabilities-non-current	[5]	$ 173	$ 170

[1] Current regulatory liabilities are presented in other current liabilities in the Dominion's and Dominion Gas' Consolidated Balance Sheets.

[2] Dominion’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[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] 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.

[5] 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.

[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] 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.

[8] Virginia Power’s Consolidated Balance Sheet at December 31, 2015 has been derived from the audited Consolidated Financial Statements at that date.

[9] Noncurrent regulatory liabilities are presented in other deferred credits and other liabilities in Dominion Gas' Consolidated Balance Sheets.

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Regulatory Assets and Liabilities (Narrative) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory assets past expenditures not earning return	$ 299
Period for which expenditures are expected to be recovered	2 years
Virginia Electric and Power Company
Public Utilities, General Disclosures [Line Items]
Regulatory assets past expenditures not earning return	$ 234
Dominion Gas Holdings, LLC
Public Utilities, General Disclosures [Line Items]
Regulatory assets past expenditures not earning return	$ 23

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Regulatory Matters (Narrative) (Details) MMBTU in Thousands, $ in Millions	1 Months Ended										12 Months Ended
	Oct. 31, 2016 USD ($) program	Sep. 30, 2016 USD ($)	Aug. 31, 2016 USD ($) MMBTU	Jun. 30, 2016 USD ($)	May 31, 2016 USD ($) kV mi	Mar. 31, 2016 USD ($)	Mar. 31, 2015 USD ($)	Aug. 31, 2009 kV	Apr. 30, 2008	Apr. 30, 2007 kV	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2008	Nov. 30, 2016 USD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory asset		$ 2,393											$ 2,216
Virginia Electric and Power Company
Public Utilities, General Disclosures [Line Items]
ROE (percentage)									11.40%
Regulatory asset		1,094											993
Virginia Electric and Power Company | Minimum
Public Utilities, General Disclosures [Line Items]
Facility operating capacity (kV) | kV								500		500
Virginia Electric and Power Company | FERC Gas Regulation | Order Regarding Transmission Rate Design for Allocation of Costs among PJM Interconnect LLC Transmission Customers | Unfavorable Regulatory Action | Settled Litigation
Public Utilities, General Disclosures [Line Items]
Amount required to pay under settlement agreement				$ 200
Duration of payment under settlement agreement				10 years
Virginia Electric and Power Company | FERC Gas Regulation | Order Regarding Transmission Rate Design for Allocation of Costs among PJM Interconnect LLC Transmission Customers | Unfavorable Regulatory Action | Settled Litigation | Regulatory asset recovered through retail rates
Public Utilities, General Disclosures [Line Items]
Regulatory asset		192
Virginia Electric and Power Company | FERC Gas Regulation | Order Regarding Transmission Rate Design for Allocation of Costs among PJM Interconnect LLC Transmission Customers | Unfavorable Regulatory Action | Settled Litigation | Other operations and maintenance | Regulatory asset recovered through retail rates
Public Utilities, General Disclosures [Line Items]
Remaining amount recorded in other operations and maintenance expense													8
Virginia Electric and Power Company | FERC Gas Regulation | Order Regarding Transmission Rate Design for Allocation of Costs among PJM Interconnect LLC Transmission Customers | Unfavorable Regulatory Action | Settled Litigation | Other deferred credits and other liabilities
Public Utilities, General Disclosures [Line Items]
Amount of contingent liability		200
Virginia Electric and Power Company | Virginia Regulation
Public Utilities, General Disclosures [Line Items]
Proposed revenue requirement					$ 1,400
Proposed revenue requirement increase (decrease)					$ (286)
Virginia Electric and Power Company | Virginia Regulation | North Anna | Intent to Sue Notification Received from Sierra Club Alleging Endangered Species Act Violations
Public Utilities, General Disclosures [Line Items]
Period of notice of intent to sue			60 days
Virginia Electric and Power Company | Virginia Regulation | Phase One of Cost Recovery to Move Electric Distribution Facilities Underground
Public Utilities, General Disclosures [Line Items]
Total projected capital investment			$ 140
Virginia Electric and Power Company | Virginia Regulation | Poland Road Substation
Public Utilities, General Disclosures [Line Items]
Capacity of transmission line (kV) | kV					230
Virginia Electric and Power Company | Virginia Regulation | Double Circuit Transmission Line between Loudoun-Brambleton Line and Poland Road Substation
Public Utilities, General Disclosures [Line Items]
Capacity of transmission line (kV) | kV					230
Length of kV line (miles) | mi					4
Virginia Electric and Power Company | Virginia Regulation | Loudoun- Brambleton Line
Public Utilities, General Disclosures [Line Items]
Capacity of transmission line (kV) | kV					230
Virginia Electric and Power Company | Virginia Regulation | Rider U
Public Utilities, General Disclosures [Line Items]
ROE (percentage)			9.60%
Approved revenue required			$ 20
Virginia Electric and Power Company | Virginia Regulation | Rider U | Phase One of Cost Recovery to Move Electric Distribution Facilities Underground
Public Utilities, General Disclosures [Line Items]
Amount of cost recovery			123
Virginia Electric and Power Company | Virginia Regulation | Rider U, 2017-2018 Rate Year
Public Utilities, General Disclosures [Line Items]
Projected capital investment			2
Virginia Electric and Power Company | Virginia Regulation | Rider U, 2018-2019 Rate Year
Public Utilities, General Disclosures [Line Items]
Projected capital investment			2
Virginia Electric and Power Company | Virginia Regulation | Subsequent Event | Rider BW
Public Utilities, General Disclosures [Line Items]
Proposed revenue requirement	$ 134
Proposed revenue requirement increase (decrease)	14
Virginia Electric and Power Company | Virginia Regulation | Subsequent Event | Rider US-2
Public Utilities, General Disclosures [Line Items]
Proposed revenue requirement	10
Proposed revenue requirement increase (decrease)	6
Virginia Electric and Power Company | Virginia Regulation | Subsequent Event | Riders C1A and C2A
Public Utilities, General Disclosures [Line Items]
Proposed revenue requirement	$ 45
Virginia Electric and Power Company | Virginia Regulation | Subsequent Event | Riders C1A and C2A | Energy Efficiency Program
Public Utilities, General Disclosures [Line Items]
Number of new energy efficiency programs | program	2
Period of cost cap	5 years
Duration of program	2 years
Virginia Electric and Power Company | Virginia Regulation | Subsequent Event | Riders C1A and C2A | Peak Shaving Program
Public Utilities, General Disclosures [Line Items]
Duration of program	5 years
Virginia Electric and Power Company | Virginia Regulation | Subsequent Event | Maximum | Riders C1A and C2A | Energy Efficiency Program
Public Utilities, General Disclosures [Line Items]
Amount of cost recovery	$ 178
Virginia Electric and Power Company | Virginia Regulation | Subsequent Event | Maximum | Riders C1A and C2A | Peak Shaving Program
Public Utilities, General Disclosures [Line Items]
Amount of cost recovery	$ 5
Virginia Electric and Power Company | North Carolina Regulation
Public Utilities, General Disclosures [Line Items]
Proposed revenue requirement increase (decrease)			$ (36)
Virginia Electric and Power Company | North Carolina Regulation | Annual Non- Fuel Base Revenues
Public Utilities, General Disclosures [Line Items]
Proposed revenue requirement increase (decrease)						$ 51
Proposed ROE percentage						10.50%
Virginia Electric and Power Company | North Carolina Regulation | Subsequent Event | Annual Non- Fuel Base Revenues
Public Utilities, General Disclosures [Line Items]
Proposed ROE percentage	9.90%
Base rate increase per stipulation and settlement agreement	$ 35
East Ohio | Ohio Regulation | PIR
Public Utilities, General Disclosures [Line Items]
Total projected capital investment							$ 200
Percentage of pipeline system														25.00%
Period for capital investment							5 years
Percentage increase in capital spend							3.00%
East Ohio | Ohio Regulation | Subsequent Event | PSMP | Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Total projected capital investment															$ 15
Hope Gas Inc | West Virginia Regulation | PREP
Public Utilities, General Disclosures [Line Items]
Amount of cost recovery		2
Total projected capital investment					$ 152
Period for capital investment					5 years
Hope Gas Inc | West Virginia Regulation | PREP | Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Projected capital investment											$ 27	$ 20
Dominion Gas Holdings, LLC
Public Utilities, General Disclosures [Line Items]
Regulatory asset		$ 491											$ 472
Dominion Gas Holdings, LLC | FERC Gas Regulation | Leidy South Project Facilities
Public Utilities, General Disclosures [Line Items]
Duration of contracts			20 years
Amount of project			$ 210
Daily firm transportation service (Dths) | MMBTU			155

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Variable Interest Entities (Narrative) (Details) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) MW generator mi	Sep. 30, 2015 USD ($)	Dec. 31, 2015 generator
Dominion Midstream Partners, LP
Variable Interest Entities [Line Items]
Ownership interest percentage of limited partner interests			65.00%
Variable Interest Entity, Primary Beneficiary | Partnership Interest | Merchant Solar Projects
Variable Interest Entities [Line Items]
Ownership percentage			67.00%
Variable Interest Entity, Primary Beneficiary | Dominion Midstream Partners, LP | Partnership Interest
Variable Interest Entities [Line Items]
Ownership interest percentage of limited partner interests			65.00%
Variable Interest Entity, Not Primary Beneficiary | Jointly Owned Natural Gas Pipeline | Atlantic Coast Pipeline | Pipelines | Gas Distribution
Variable Interest Entities [Line Items]
Ownership percentage			48.00%
Length of natural gas pipeline (in miles) | mi			600
Variable Interest Entity, Not Primary Beneficiary | Virginia Electric and Power Company
Variable Interest Entities [Line Items]
Long term capacity contract non utility generators (generators) | generator			3		5
Number of expired non-utility generators | generator					2
Aggregate generation capacity from long-term power and capacity contracts (MW) | MW			418
Remaining purchase commitments			$ 320
Payment for electric capacity	$ 37	$ 52	111	$ 160
Payment for electric energy	11	17	23	77
Shared services purchased	80	73	$ 268	239
Variable Interest Entity, Not Primary Beneficiary | Virginia Electric and Power Company | Minimum
Variable Interest Entities [Line Items]
Contracts expiry date start range			2017
Variable Interest Entity, Not Primary Beneficiary | Virginia Electric and Power Company | Maximum
Variable Interest Entities [Line Items]
Contracts expiry date start range			2021
Variable Interest Entity, Not Primary Beneficiary | Dominion Gas Holdings, LLC
Variable Interest Entities [Line Items]
Shared services purchased	$ 31	$ 27	$ 95	$ 85

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Significant Financing Transactions (Commercial Paper, Bank Loans and Letters of Credit Outstanding) (Details) - USD ($)		9 Months Ended
		Sep. 30, 2016	Sep. 01, 2016
Line of Credit Facility [Line Items]
Facility Limit		$ 6,250,000,000
Outstanding Commercial Paper		3,097,000,000
Outstanding Letters of Credit		60,000,000
Facility Capacity Available		3,093,000,000
Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit	[1]	5,500,000,000
Outstanding Commercial Paper		965,000,000
Outstanding Letters of Credit		0
Dominion Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit	[2]	1,500,000,000
Outstanding Commercial Paper		60,000,000
Outstanding Letters of Credit		0
Joint Revolving Credit Facility 4 Billion and Joint Revolving Credit Facility 500 Million | Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit		2,000,000,000.0
Joint Revolving Credit Facility 4 Billion and Joint Revolving Credit Facility 500 Million | Dominion Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit		1,500,000,000.0
Joint Revolving Credit Facility 4 Billion and Joint Revolving Credit Facility 500 Million | Line of Credit | Dominion Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit		750,000,000	$ 1,000,000,000.0
Joint Revolving Credit Facility 4 Billion and Joint Revolving Credit Facility 500 Million | Letter of Credit
Line of Credit Facility [Line Items]
Facility Limit		2,000,000,000.0
Joint Revolving Credit Facility 4 Billion and Joint Revolving Credit Facility 500 Million | Letter of Credit | Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit		2,000,000,000.0
Joint Revolving Credit Facility 4 Billion and Joint Revolving Credit Facility 500 Million | Letter of Credit | Dominion Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit		1,500,000,000.0
Credit Facility 4 Billion
Line of Credit Facility [Line Items]
Facility Limit	[3]	5,000,000,000
Outstanding Commercial Paper	[3]	3,073,000,000
Outstanding Letters of Credit	[3]	0
Facility Capacity Available	[3]	1,927,000,000
Credit Facility 4 Billion | Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit	[1]	5,000,000,000
Outstanding Commercial Paper	[1]	965,000,000
Outstanding Letters of Credit	[1]	0
Credit Facility 4 Billion | Dominion Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit	[2]	1,000,000,000
Outstanding Commercial Paper	[2]	60,000,000
Outstanding Letters of Credit	[2]	0
Credit Facility 500 Million
Line of Credit Facility [Line Items]
Facility Limit	[3]	500,000,000
Outstanding Commercial Paper	[3]	0
Outstanding Letters of Credit	[3]	60,000,000
Facility Capacity Available	[3]	440,000,000
Credit Facility 500 Million | Virginia Electric and Power Company
Line of Credit Facility [Line Items]
Facility Limit	[1]	500,000,000
Outstanding Commercial Paper	[1]	0
Outstanding Letters of Credit	[1]	0
Credit Facility 500 Million | Dominion Gas Holdings, LLC
Line of Credit Facility [Line Items]
Facility Limit	[2]	500,000,000
Outstanding Commercial Paper	[2]	0
Outstanding Letters of Credit	[2]	0
Revolving multi-year credit facility | Dominion Questar Corporation
Line of Credit Facility [Line Items]
Facility Limit	[4]	500,000,000
Outstanding Commercial Paper	[4]	24,000,000
Outstanding Letters of Credit	[4]	0
Facility Capacity Available	[4]	476,000,000
Revolving 364-day credit facility | Dominion Questar Corporation
Line of Credit Facility [Line Items]
Facility Limit	[4]	250,000,000
Outstanding Commercial Paper	[4]	0
Outstanding Letters of Credit	[4]	0
Facility Capacity Available	[4]	$ 250,000,000
Term of revolving credit facility	[4]	364 days

[1] The full amount of the facilities is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion and Dominion Gas. Sub-limits for Virginia Power are set within the facility limit but can be changed at the option of the Companies multiple times per year. At September 30, 2016, the aggregate sub-limit for Virginia Power was $2.0 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion. In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

[2] A maximum of a combined $1.5 billion of the facilities is available to Dominion Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion and Virginia Power. Sub-limits for Dominion Gas are set within the facility limit but can be changed at the option of the Companies multiple times per year. In September 2016, the aggregate sub-limit for Dominion Gas was decreased from $1.0 billion to $750 million. If Dominion Gas has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion. In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

[3] In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used by the Companies to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

[4] These Dominion Questar facilities were terminated in October 2016.

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Significant Financing Transactions (Narrative) (Details)					1 Months Ended						9 Months Ended
		Aug. 15, 2016 USD ($) shares	Jul. 01, 2016 shares	Apr. 01, 2016 shares	Aug. 31, 2019 shares	Nov. 30, 2016 USD ($)	Aug. 31, 2016 USD ($)	Jul. 31, 2016 USD ($) shares	Apr. 30, 2016 USD ($) shares	Dec. 31, 2014 USD ($) agreement	Sep. 30, 2016 USD ($) facility $ / shares shares	Sep. 30, 2015 USD ($)	Oct. 31, 2016 USD ($)	Oct. 01, 2016 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2016 EUR (€)	May 31, 2016 USD ($)	Mar. 31, 2016 USD ($)	Jun. 30, 2015 USD ($)
Debt Instrument [Line Items]
Amount issued for 2016 Series A Equity Units											$ 2,079,000,000
Issuance of common stock											$ 2,079,000,000	$ 717,000,000
Shelf Registration for Sale of Common Stock through At-the-market Program
Debt Instrument [Line Items]
Number of sales agency agreements | agreement										4
Common stock reserved for issuance in connection with stock purchase contracts (up to $200 million)																			$ 200,000,000
Underwritten Public Offering
Debt Instrument [Line Items]
Number of common units issued | shares									10,200,000
Issuance of common stock									$ 756,000,000
Maximum | Shelf Registration for Sale of Common Stock through At-the-market Program
Debt Instrument [Line Items]
Aggregate amount of common stock in which the company may offer under SEC shelf registration (up to $500 million)										$ 500,000,000
Common Stock
Debt Instrument [Line Items]
Shares of common stock reserved for issuance with stock purchase contracts | shares											23,100,000
Scenario, Forecast | Minimum
Debt Instrument [Line Items]
Shares to be issued under purchase contracts | shares					15,000,000
Scenario, Forecast | Maximum
Debt Instrument [Line Items]
Shares to be issued under purchase contracts | shares					18,700,000
Series A RSNs
Debt Instrument [Line Items]
Units Issued | shares	[1]	28,000,000
Amount issued for 2016 Series A Equity Units							$ 1,400,000,000.0
Purchase price to be paid under stock purchase contracts (in dollars per corporate unit) | $ / shares											$ 50
Remarketable Subordinated Notes | Series A RSNs
Debt Instrument [Line Items]
Total Long-term Debt	[1]	$ 1,400,000,000.0
Interest rate percentage	[1],[2]	2.00%
Units Issued | shares			8,500,000.0	8,500,000.0				8,500,000.0	8,500,000.0
Remarketable Subordinated Notes, 2013 Series A, due 2021 | Series A RSNs
Debt Instrument [Line Items]
Total Long-term Debt																		$ 550,000,000
Interest rate percentage																		1.07%
Remarketable Subordinated Notes, 2013 Series B, due 2019 | Series B RSNs
Debt Instrument [Line Items]
Total Long-term Debt																	$ 550,000,000
Interest rate percentage																	1.18%
Remarketable Subordinated Notes, 2016 Series A-1, due 2021
Debt Instrument [Line Items]
Interest in RSNs issued by Dominion (percentage)											2.50%
Remarketable Subordinated Notes, 2016 Series A-1, due 2021 | Series A RSNs
Debt Instrument [Line Items]
Total Long-term Debt		$ 700,000,000
Remarketable Subordinated Notes, 2016 Series A-2, due 2024
Debt Instrument [Line Items]
Interest in RSNs issued by Dominion (percentage)											2.50%
Remarketable Subordinated Notes, 2016 Series A-2, due 2024 | Series A RSNs
Debt Instrument [Line Items]
Total Long-term Debt		$ 700,000,000
Series A Junior Subordinated Notes | Enhanced Junior Subordinated Notes
Debt Instrument [Line Items]
Interest rate percentage																		4.104%
Series B Junior Subordinated Notes | Enhanced Junior Subordinated Notes
Debt Instrument [Line Items]
Interest rate percentage																	2.962%
June 2006 and September 2006 hybrids | Maximum | Enhanced Junior Subordinated Notes
Debt Instrument [Line Items]
Amount purchased and cancelled								$ 200,000,000
June 2006 hybrids | Enhanced Junior Subordinated Notes
Debt Instrument [Line Items]
Amount purchased and cancelled								125,000,000										$ 38,000,000
September 2006 hybrids | Enhanced Junior Subordinated Notes
Debt Instrument [Line Items]
Amount purchased and cancelled								74,000,000										$ 4,000,000
July 2016 Hybrids | Enhanced Junior Subordinated Notes
Debt Instrument [Line Items]
Total Long-term Debt								$ 800,000,000
Interest rate percentage								5.25%
1.60% Senior Notes Due in 2019 | Senior Notes
Debt Instrument [Line Items]
Total Long-term Debt															$ 500,000,000
Interest rate percentage															1.60%	1.60%
2.0% Senior Notes Due in 2021 | Senior Notes
Debt Instrument [Line Items]
Total Long-term Debt															$ 400,000,000
Interest rate percentage															2.00%	2.00%
2.85% Senior Notes Due in 2026 | Senior Notes
Debt Instrument [Line Items]
Total Long-term Debt															$ 400,000,000
Interest rate percentage															2.85%	2.85%
1.50% Senior Notes Due in 2018 | Senior Notes
Debt Instrument [Line Items]
Total Long-term Debt											$ 300,000,000
Interest rate percentage											1.50%
Private Placement Term Loan Agreement Maturing in September 2017 | Term loan agreement
Debt Instrument [Line Items]
Total Long-term Debt											$ 1,200,000,000.0
Private Placement Term Loan Agreement Maturing in September 2017 | Term loan agreement | Long-term Debt
Debt Instrument [Line Items]
Borrowings under private placement term loan included in long term debt											$ 348,000,000
Virginia Electric and Power Company
Debt Instrument [Line Items]
Number of joint revolving credit facilities | facility											2
Credit facility											$ 120,000,000
Virginia Electric and Power Company | Subsequent Event
Debt Instrument [Line Items]
Credit facility													$ 100,000,000	$ 120,000,000
Virginia Electric and Power Company | Tax Exempt Debt
Debt Instrument [Line Items]
Variable rate tax-exempt financings											$ 100,000,000
Dominion Gas Holdings, LLC
Debt Instrument [Line Items]
Number of joint revolving credit facilities | facility											2
Dominion Gas Holdings, LLC | 3.8% Senior Notes Due in 2031 | Senior Notes
Debt Instrument [Line Items]
Total Long-term Debt																	$ 150,000,000
Interest rate percentage																	3.80%
Dominion Gas Holdings, LLC | 2.875% Senior Notes Due in 2023 | Senior Notes
Debt Instrument [Line Items]
Total Long-term Debt															$ 250,000,000
Interest rate percentage															2.875%	2.875%
Dominion Gas Holdings, LLC | 1.45% Senior Notes Due in 2026 | Senior Notes
Debt Instrument [Line Items]
Total Long-term Debt | €																€ 250,000,000
Interest rate percentage															1.45%	1.45%
Dominion Gas Holdings, LLC | 1.45% Senior Notes Due in 2026 | Senior Notes | Long-term Debt
Debt Instrument [Line Items]
Total Long-term Debt															$ 280,000,000
Amount of senior notes at period end											$ 281,000,000
Dominion Midstream Partners, LP | Subsequent Event | Scenario, Forecast | Underwritten Public Offering | Limited Partner
Debt Instrument [Line Items]
Net proceeds from issuance and public offering of common units						$ 348,000,000

[1] The maturity dates of the $700 million Series A-1 RSNs and $700 million Series A-2 RSNs are August 15, 2021 and August 15, 2024, respectively.

[2] Annual interest rate applies to each of the Series A-1 RSNs and Series A-2 RSNs.

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Significant Financing Transactions (Schedule of Equity Units) (Details) - Series A RSNs - USD ($)					1 Months Ended
		Aug. 15, 2016	Jul. 01, 2016	Apr. 01, 2016	Jul. 31, 2016	Apr. 30, 2016
Capital Unit [Line Items]
Units Issued	[1]	28,000,000
Total Net Proceeds	[1]	$ 1,374,800,000
Stock Purchase Contract Annual Rate	[1]	4.75%
Stock Purchase Contract Liability	[1]	$ 190,600,000
Remarketable Subordinated Notes
Capital Unit [Line Items]
Units Issued			8,500,000.0	8,500,000.0	8,500,000.0	8,500,000.0
Total Long-term Debt	[1]	$ 1,400,000,000.0
RSN Annual Interest Rate	[1],[2]	2.00%
Remarketable Subordinated Notes, 2016 Series A-1, due 2021
Capital Unit [Line Items]
Total Long-term Debt		$ 700,000,000
Remarketable Subordinated Notes, 2016 Series A-2, due 2024
Capital Unit [Line Items]
Total Long-term Debt		$ 700,000,000

[1] The maturity dates of the $700 million Series A-1 RSNs and $700 million Series A-2 RSNs are August 15, 2021 and August 15, 2024, respectively.

[2] Annual interest rate applies to each of the Series A-1 RSNs and Series A-2 RSNs.

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Commitments and Contingencies (Narrative) (Details)	1 Months Ended													9 Months Ended	12 Months Ended
	Apr. 30, 2017	Jul. 31, 2016 party	Jun. 30, 2016 party	Apr. 30, 2016 USD ($)	Oct. 31, 2015	Jun. 30, 2015 party	Apr. 30, 2015 facility	Dec. 31, 2014 USD ($)	Oct. 31, 2014 facility	Jun. 30, 2014 unit	Jul. 31, 2013 unit	Sep. 30, 2011 party	Jul. 31, 2011 state group MW	Sep. 30, 2016 USD ($) facility party site	Dec. 31, 2015 USD ($) party
CWA | Virginia Electric and Power Company | Possum Point Power Station | Other operations and maintenance
Loss Contingencies [Line Items]
Charge as a result of settlement offer								$ 121,000,000
Unfavorable Regulatory Action | EPA | Maximum
Loss Contingencies [Line Items]
Maximum period for consideration of CO2 emissions from biomass projects													3 years
Unfavorable Regulatory Action | EPA | Virginia Electric and Power Company
Loss Contingencies [Line Items]
Number of coal fired generating units | unit											3
Unfavorable Regulatory Action | MATS | EPA
Loss Contingencies [Line Items]
Extension period for MATS compliance										1 year
Number of coal fired generating units | unit										2
Requested compliance extension under EPA Administrative Order					1 year
Unfavorable Regulatory Action | MATS | EPA | Scenario, Forecast
Loss Contingencies [Line Items]
Period to be in service following receipt of all required permits	20 months
Unfavorable Regulatory Action | MATS | EPA | Maximum
Loss Contingencies [Line Items]
Extension period for MATS compliance				1 year
Unfavorable Regulatory Action | CAIR | EPA
Loss Contingencies [Line Items]
Number of states under EPA replacement rule | state													28
Number of groups of affected states | group													2
Unfavorable Regulatory Action | CAIR | EPA | Minimum
Loss Contingencies [Line Items]
Emissions of fossil fuel fired electric generating units (MW) | MW													25
Unfavorable Regulatory Action | Regulations to Reduce Nitrogen Oxide and Volatile Organic Compounds Emissions | Pennsylvania Department of Environmental Protection | Dominion Gas Holdings, LLC
Loss Contingencies [Line Items]
Estimated compliance costs				$ 25,000,000
Unfavorable Regulatory Action | CWA
Loss Contingencies [Line Items]
Number of facilities that may be subject to final regulations | facility									14
Unfavorable Regulatory Action | CWA | Virginia Electric and Power Company
Loss Contingencies [Line Items]
Number of facilities that may be subject to final regulations | facility									11
Unfavorable Regulatory Action | CWA | EPA | Final Rule to Revise Effluent Limitations Guidelines for Steam Electric Power Generating Category
Loss Contingencies [Line Items]
Number of facilities that maybe subject to additional wastewater treatment requirements | facility														8
Unfavorable Regulatory Action | CERCLA | EPA
Loss Contingencies [Line Items]
Number of parties issued UAO | party												22
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA
Loss Contingencies [Line Items]
Number of former manufactured gas plant sites | site														19
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA | Former Gas Plant Site with Post Closure Groundwater Monitoring Program
Loss Contingencies [Line Items]
Number of former sites | site														1
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA | Dominion Gas Holdings, LLC
Loss Contingencies [Line Items]
Number of former manufactured gas plant sites | site														12
Unfavorable Regulatory Action | Coal Tar and Other Potentially Harmful Materials | EPA | Virginia Electric and Power Company
Loss Contingencies [Line Items]
Number of former manufactured gas plant sites | site														3
Preliminary costs for options under evaluation for site, minimum														$ 1,000,000
Preliminary costs for options under evaluation for site, maximum														22,000,000
Unfavorable Regulatory Action | CCR | EPA | Virginia Electric and Power Company | Environmental Protection Agency Final Rule Regulating Management of CCRs | Facilities Subject to CCR Final Rule
Loss Contingencies [Line Items]
Number of facilities with CCR | facility							8
Obligations incurred during the period															$ 386,000,000
Unfavorable Regulatory Action | CCR | EPA | Virginia Electric and Power Company | Environmental Protection Agency Final Rule Regulating Management of CCRs | Facilities Subject to CCR Final Rule | Other operations and maintenance
Loss Contingencies [Line Items]
Incremental charge upon recognition of ARO															99,000,000
Unfavorable Regulatory Action | CCR | EPA | Virginia Electric and Power Company | Environmental Protection Agency Final Rule Regulating Management of CCRs | Facilities Subject to CCR Final Rule | ARO's
Loss Contingencies [Line Items]
Increase in property plant and equipment associated with asset retirement costs															166,000,000
Unfavorable Regulatory Action | CCR | EPA | Virginia Electric and Power Company | Environmental Protection Agency Final Rule Regulating Management of CCRs | Facilities Subject to CCR Final Rule | Noncurrent Liabilities
Loss Contingencies [Line Items]
Reduction in other current liabilities															$ 121,000,000
Unfavorable Regulatory Action | CCR | EPA | Virginia Electric and Power Company | Pending Litigation | Environmental Protection Agency Final Rule Regulating Management of CCRs | Facilities Subject to CCR Final Rule | Administrative Appeals in Circuit Court for the City of Richmond
Loss Contingencies [Line Items]
Number of parties | party															2
Unfavorable Regulatory Action | CCR | EPA | Virginia Electric and Power Company | Settled Litigation | Environmental Protection Agency Final Rule Regulating Management of CCRs | Facilities Subject to CCR Final Rule | Administrative Appeals in Circuit Court for the City of Richmond
Loss Contingencies [Line Items]
Number of parties | party			1
Breach of Contract Lawsuit | DTI | Pending Litigation
Loss Contingencies [Line Items]
Accrued liability for legal matter														$ 6,000,000
Liquefaction Project | FERC | Cove Point | Pending Litigation
Loss Contingencies [Line Items]
Number of parties | party														2
Liquefaction Project | FERC | Cove Point | Judicial Ruling
Loss Contingencies [Line Items]
Number of parties | party		1				1

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Commitments and Contingencies (Subsidiary Guarantees) (Details)	9 Months Ended
	Sep. 30, 2016 USD ($) guarantee subsidiary
Guarantor Obligations [Line Items]
Stated Limit	$ 6,807,000,000
Value	$ 1,594,000,000	[1]
Number of DEI subsidiaries | subsidiary	2
Purchased surety bonds	$ 147,000,000
Authorized issuance of standby letters of credit	60,000,000
Minimum
Guarantor Obligations [Line Items]
Annual future contributions	4,000,000
Maximum
Guarantor Obligations [Line Items]
Annual future contributions	19,000,000
Third Party and Equity Method Investee
Guarantor Obligations [Line Items]
Amount of civil penalty	73,000,000
Stated Limit	43,000,000
Cove Point
Guarantor Obligations [Line Items]
Stated Limit	$ 150,000,000
Number of guarantees with no stated limit | guarantee	2
Number of guarantees | guarantee	1
Aggregate limit	$ 1,750,000,000
Annual draw limit	175,000,000
Subsidiary Debt
Guarantor Obligations [Line Items]
Stated Limit	27,000,000	[2]
Value	27,000,000	[1],[2]
Commodity Transactions
Guarantor Obligations [Line Items]
Stated Limit	2,081,000,000	[3]
Value	874,000,000	[1],[3]
Nuclear Obligations
Guarantor Obligations [Line Items]
Stated Limit	169,000,000	[4]
Value	94,000,000	[1],[4]
Nuclear Obligations | Millstone
Guarantor Obligations [Line Items]
Stated Limit	150,000,000
Nuclear Obligations | Kewaunee
Guarantor Obligations [Line Items]
Stated Limit	60,000,000
Cove Point
Guarantor Obligations [Line Items]
Stated Limit	1,900,000,000	[5]
Value	0	[1],[5]
Solar
Guarantor Obligations [Line Items]
Stated Limit	1,847,000,000	[6]
Value	539,000,000	[1],[6]
Other
Guarantor Obligations [Line Items]
Stated Limit	783,000,000	[7]
Value	60,000,000	[1],[7]
Through 2019 | Third Party and Equity Method Investee
Guarantor Obligations [Line Items]
Stated Limit	36,000,000
Virginia Electric and Power Company
Guarantor Obligations [Line Items]
Purchased surety bonds	70,000,000
Dominion Gas Holdings, LLC
Guarantor Obligations [Line Items]
Purchased surety bonds	$ 21,000,000

[1] Represents the estimated portion of the guarantee's stated limit that is utilized as of September 30, 2016 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion's subsidiaries, the value includes the recorded amount.

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

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

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

[5] Guarantees related to Cove Point, in support of terminal services, transportation and construction. Two of the guarantees have no stated limit, one guarantee has a $150 million limit, and one guarantee has a $1.75 billion aggregate limit with an annual draw limit of $175 million.

[6] Includes guarantees related to solar projects including guarantees that do not have stated limits. Also includes guarantees related to solar projects entered into by DEI on behalf of certain subsidiaries.

[7] Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries' obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of September 30, 2016, Dominion's maximum remaining cumulative exposure under these equity funding agreements is $36 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits.

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Credit Risk (Narrative) (Details) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016 USD ($) counterparty	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) counterparty	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Concentration Risk and Guarantor Obligations [Line Items]
Gross credit exposure				$ 96
Operating Revenue		$ 3,132	$ 2,971	8,651	$ 9,127
Additional collateral to be posted if the credit related contingent features were triggered		7		7		$ 12
Aggregate fair value of all derivative instruments with credit contingent provisions that are in a liability position		18		18		$ 49
Virginia Electric and Power Company
Concentration Risk and Guarantor Obligations [Line Items]
Operating Revenue	[1]	$ 2,211	$ 2,058	$ 5,877	$ 6,008
Credit Concentration Risk
Concentration Risk and Guarantor Obligations [Line Items]
Number of counterparties | counterparty		0		0
Amount of exposure for single counterparty				$ 21
Credit Concentration Risk | Wholesale Customers | Sales to wholesale customers | Virginia Electric and Power Company
Concentration Risk and Guarantor Obligations [Line Items]
Number of counterparties | counterparty		0		0
Operating Revenue				$ 23
Amount of exposure related to sales to wholesale customers for single counterparty				$ 4
Credit Concentration Risk | Investment Grade
Concentration Risk and Guarantor Obligations [Line Items]
Concentration risk, percentage (percentage)				70.00%
Credit Concentration Risk | Investment Grade | Virginia Electric and Power Company
Concentration Risk and Guarantor Obligations [Line Items]
Concentration risk, percentage (percentage)				35.00%

[1] See Note 17 for amounts attributable to affiliates.

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Related-Party Transactions (Details) - USD ($)		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Derivative Asset		$ 295,000,000		$ 295,000,000		$ 388,000,000
Derivative Liabilities		422,000,000		422,000,000		343,000,000
Capital expenditures				4,536,000,000	$ 3,632,000,000
Virginia Electric and Power Company
Related Party Transaction [Line Items]
Derivative Asset		118,000,000		118,000,000		127,000,000
Derivative Liabilities		291,000,000		291,000,000		86,000,000
Commodity purchases from affiliates		172,000,000	$ 123,000,000	416,000,000	469,000,000
Services provided by affiliates	[1]	105,000,000	96,000,000	347,000,000	313,000,000
Services provided to affiliates		5,000,000	5,000,000	17,000,000	15,000,000
Capital expenditures				1,835,000,000	1,840,000,000
Outstanding borrowings, net of repayments, under money pool for non-regulated subsidiaries		0		0		0
Virginia Electric and Power Company | Affiliate
Related Party Transaction [Line Items]
Derivative Asset		28,000,000		28,000,000		13,000,000
Derivative Liabilities		15,000,000		15,000,000		22,000,000
Virginia Electric and Power Company | Affiliate | Services provided by affiliates
Related Party Transaction [Line Items]
Capital expenditures		32,000,000	32,000,000	109,000,000	105,000,000
Virginia Electric and Power Company | Principal Owner
Related Party Transaction [Line Items]
Short term demand note		0		0		376,000,000
Virginia Electric and Power Company | Other deferred credits and other liabilities
Related Party Transaction [Line Items]
Amounts due to Dominion		376,000,000		376,000,000		316,000,000
Virginia Electric and Power Company | Other deferred charges and other assets
Related Party Transaction [Line Items]
Amounts due from Dominion		111,000,000		111,000,000		77,000,000
Dominion Gas Holdings, LLC
Related Party Transaction [Line Items]
Derivative Asset		14,000,000		14,000,000		11,000,000
Derivative Liabilities		6,000,000		6,000,000		14,000,000
Amounts due from Dominion	[2]	1,000,000		1,000,000		1,000,000
Commodity purchases from affiliates		2,000,000	3,000,000	7,000,000	7,000,000
Services provided by affiliates	[3]	34,000,000	30,000,000	94,000,000	75,000,000
Services provided to affiliates		16,000,000	17,000,000	51,000,000	52,000,000
Capital expenditures				610,000,000	514,000,000
Other receivables	[4]	9,000,000		9,000,000		7,000,000
Customer receivables from related parties		1,000,000		1,000,000		4,000,000
Affiliated notes receivable	[5]	17,000,000		17,000,000		14,000,000
Dominion Gas Holdings, LLC | Revolving Credit Facility | IRCA
Related Party Transaction [Line Items]
Borrowings under IRCA						95,000,000
Dominion Gas Holdings, LLC | Services provided by affiliates
Related Party Transaction [Line Items]
Commodity purchases from affiliates	[6]	36,000,000	30,000,000	108,000,000	99,000,000
Dominion Gas Holdings, LLC | Affiliate | Services provided by affiliates
Related Party Transaction [Line Items]
Capital expenditures		13,000,000	$ 16,000,000	37,000,000	$ 40,000,000
Dominion Gas Holdings, LLC | Noncurrent Pension and Other Postretirement Benefit Assets
Related Party Transaction [Line Items]
Amounts due from Dominion, noncurrent		$ 686,000,000		$ 686,000,000		$ 652,000,000

[1] Includes capitalized expenditures of $32 million for both the three months ended September 30, 2016 and 2015, and $109 million and $105 million for the nine months ended September 30, 2016 and 2015, respectively.

[2] Amounts are presented in other current assets in Dominion Gas' Consolidated Balance Sheets.

[3] Amounts primarily attributable to Atlantic Coast Pipeline.

[4] Represents amounts due from Atlantic Coast Pipeline, a related-party VIE.

[5] Amounts are presented in other deferred charges and other assets in Dominion Gas' Consolidated Balance Sheets.

[6] Includes capitalized expenditures of $13 million and $16 million for the three months ended September 30, 2016 and 2015, respectively, and $37 million and $40 million for the nine months ended September 30, 2016 and 2015

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Employee Benefit Plans (Narrative) (Details)	3 Months Ended	9 Months Ended
	Sep. 30, 2016 USD ($)	Sep. 30, 2016 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined benefit pension plans and OPEB plans		$ 0
Expected contribution to voluntary employees' beneficiary association		12,000,000
Medical Coverage for Local 50 retirees
Defined Benefit Plan Disclosure [Line Items]
Retirement age	65 years
Decrease in accumulated postretirement benefit obligation	$ 37,000,000	37,000,000
Increase in net periodic benefit credit	$ 9,000,000	$ 9,000,000
Discount rate percentage	3.71%	3.71%
Dominion Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Contributions to defined benefit pension plans and OPEB plans		$ 0
Expected contribution to voluntary employees' beneficiary association		12,000,000
Special Termination Benefits | Organizational Design Initiative
Defined Benefit Plan Disclosure [Line Items]
Organizational design initiative		65,000,000
Organizational design initiative, after tax		40,000,000
Special Termination Benefits | Organizational Design Initiative | Virginia Electric and Power Company
Defined Benefit Plan Disclosure [Line Items]
Organizational design initiative		33,000,000
Organizational design initiative, after tax		20,000,000
Special Termination Benefits | Organizational Design Initiative | Dominion Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Organizational design initiative		8,000,000
Organizational design initiative, after tax		$ 5,000,000

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Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 30	$ 32	$ 87	$ 95
Interest cost	79	71	234	215
Expected return on plan assets	(141)	(132)	(419)	(398)
Amortization of prior service cost (credit)	0	0	1	1
Amortization of net actuarial loss	29	40	84	120
Net periodic benefit cost (credit)	(3)	11	(13)	33
Pension Benefits | Dominion Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Service cost	3	4	10	11
Interest cost	7	7	22	21
Expected return on plan assets	(33)	(31)	(100)	(94)
Amortization of net actuarial loss	3	5	10	15
Net periodic benefit cost (credit)	(20)	(15)	(58)	(47)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	7	10	23	30
Interest cost	16	17	50	50
Expected return on plan assets	(28)	(29)	(87)	(88)
Amortization of prior service cost (credit)	(9)	(7)	(23)	(20)
Amortization of net actuarial loss	2	1	5	4
Net periodic benefit cost (credit)	(12)	(8)	(32)	(24)
Other Postretirement Benefits | Dominion Gas Holdings, LLC
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	2	4	5
Interest cost	3	3	10	10
Expected return on plan assets	(5)	(6)	(17)	(18)
Amortization of net actuarial loss	0	1	1	2
Net periodic benefit cost (credit)	$ (1)	$ 0	$ (2)	$ (1)

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Operating Segments (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Segment Reporting Information [Line Items]
After tax net expense (benefit)	$ 1,987,000,000	$ 1,848,000,000	$ 5,843,000,000	$ 6,229,000,000
Operating Segments
Segment Reporting Information [Line Items]
After tax net expenses			22,000,000	80,000,000
Operating Segments | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative			59,000,000
Organizational design initiative, after tax			36,000,000
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
After tax net expenses			63,000,000	82,000,000
Operating Segments | DVP | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative, after tax			5,000,000
Operating Segments | Dominion Energy | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative, after tax			12,000,000
Operating Segments | Dominion Generation
Segment Reporting Information [Line Items]
Net gain on investments			29,000,000	39,000,000
Net gain on investments, after tax			18,000,000	25,000,000
Operating Segments | Dominion Generation | PJM
Segment Reporting Information [Line Items]
Billing adjustment				17,000,000
Billing adjustment, net of tax				10,000,000
Operating Segments | Dominion Generation | Facilities Subject to CCR Final Rule
Segment Reporting Information [Line Items]
Charge related to incremental future ash pond and landfill closure costs				45,000,000
Charge related to incremental future ash pond and landfill closure costs, after tax				28,000,000
Operating Segments | Dominion Generation | Virginia Regulation | Deferred Fuel Costs
Segment Reporting Information [Line Items]
Write off of deferred fuel balances				85,000,000
Write off of deferred fuel balances, net of tax				52,000,000
Operating Segments | Dominion Generation | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative, after tax			19,000,000
Virginia Electric and Power Company
Segment Reporting Information [Line Items]
After tax net expense (benefit)	1,297,000,000	1,317,000,000	3,896,000,000	4,261,000,000
Virginia Electric and Power Company | Operating Segments | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative			33,000,000
Organizational design initiative, after tax			20,000,000
Virginia Electric and Power Company | Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
After tax net expenses				101,000,000
After tax net expense (benefit)			18,000,000
Virginia Electric and Power Company | Operating Segments | DVP | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative, after tax			5,000,000
Virginia Electric and Power Company | Operating Segments | Dominion Generation | PJM
Segment Reporting Information [Line Items]
Billing adjustment				15,000,000
Billing adjustment, net of tax				9,000,000
Virginia Electric and Power Company | Operating Segments | Dominion Generation | Facilities Subject to CCR Final Rule
Segment Reporting Information [Line Items]
Charge related to incremental future ash pond and landfill closure costs				45,000,000
Charge related to incremental future ash pond and landfill closure costs, after tax				28,000,000
Virginia Electric and Power Company | Operating Segments | Dominion Generation | Virginia Regulation | Deferred Fuel Costs
Segment Reporting Information [Line Items]
Write off of deferred fuel balances				85,000,000
Write off of deferred fuel balances, net of tax				52,000,000
Virginia Electric and Power Company | Operating Segments | Dominion Generation | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative, after tax			15,000,000
Dominion Gas Holdings, LLC
Segment Reporting Information [Line Items]
After tax net expense (benefit)	$ 249,000,000	$ 163,000,000	687,000,000	665,000,000
Dominion Gas Holdings, LLC | Operating Segments | Organizational Design Initiative
Segment Reporting Information [Line Items]
Organizational design initiative			8,000,000
Organizational design initiative, after tax			5,000,000
Dominion Gas Holdings, LLC | Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
After tax net expenses			7,000,000	$ 0
After tax net expense (benefit)			$ (5,000,000)

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Operating Segments (Schedule of Segment Reporting Information, by Segment) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Segment Reporting Information [Line Items]
Total revenue from external customers		$ 3,132	$ 2,971	$ 8,651	$ 9,127
Net income (loss) attributable to Dominion		690	593	1,666	1,542
DVP
Segment Reporting Information [Line Items]
Total revenue from external customers		620	543	1,699	1,617
Dominion Generation
Segment Reporting Information [Line Items]
Total revenue from external customers	[1]	1,949	1,894	5,211	5,544
Dominion Energy
Segment Reporting Information [Line Items]
Total revenue from external customers	[1]	564	536	1,742	1,960
Corporate and Other
Segment Reporting Information [Line Items]
Total revenue from external customers		146	128	477	405
Operating Segments | DVP
Segment Reporting Information [Line Items]
Total revenue from external customers		614	539	1,682	1,603
Net income (loss) attributable to Dominion		139	125	363	382
Operating Segments | Dominion Generation
Segment Reporting Information [Line Items]
Total revenue from external customers	[1]	1,947	1,892	5,204	5,533
Net income (loss) attributable to Dominion	[1]	650	390	1,066	902
Operating Segments | Dominion Energy
Segment Reporting Information [Line Items]
Total revenue from external customers	[1]	359	377	1,235	1,376
Net income (loss) attributable to Dominion	[1]	135	153	483	509
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total revenue from external customers		2	0	8	(9)
Net income (loss) attributable to Dominion		(234)	(75)	(246)	(251)
Intersegment revenue
Segment Reporting Information [Line Items]
Total revenue from external customers	[1]	(357)	(293)	(1,000)	(1,023)
Intersegment revenue | DVP
Segment Reporting Information [Line Items]
Total revenue from external customers		6	4	17	14
Intersegment revenue | Dominion Generation
Segment Reporting Information [Line Items]
Total revenue from external customers	[1]	2	2	7	11
Intersegment revenue | Dominion Energy
Segment Reporting Information [Line Items]
Total revenue from external customers	[1]	205	159	507	584
Intersegment revenue | Corporate and Other
Segment Reporting Information [Line Items]
Total revenue from external customers		144	128	469	414
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Total revenue from external customers	[1]	210	163	522	624
Net income (loss) attributable to Dominion	[1]	0	0	0	0
Eliminations
Segment Reporting Information [Line Items]
Total revenue from external customers	[1]	(147)	(130)	(478)	(399)
Virginia Electric and Power Company
Segment Reporting Information [Line Items]
Total revenue from external customers	[2]	2,211	2,058	5,877	6,008
Net income (loss) attributable to Dominion		503	385	1,046	900
Virginia Electric and Power Company | Operating Segments | DVP
Segment Reporting Information [Line Items]
Total revenue from external customers		617	541	1,686	1,610
Net income (loss) attributable to Dominion		140	125	362	382
Virginia Electric and Power Company | Operating Segments | Dominion Generation
Segment Reporting Information [Line Items]
Total revenue from external customers		1,594	1,523	4,191	4,419
Net income (loss) attributable to Dominion		359	273	699	618
Virginia Electric and Power Company | Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total revenue from external customers		0	(6)	0	(21)
Net income (loss) attributable to Dominion		4	(13)	(15)	(100)
Dominion Gas Holdings, LLC
Segment Reporting Information [Line Items]
Total revenue from external customers	[3]	382	365	1,181	1,291
Net income (loss) attributable to Dominion		83	111	286	357
Dominion Gas Holdings, LLC | Operating Segments | Dominion Energy
Segment Reporting Information [Line Items]
Total revenue from external customers		382	365	1,181	1,291
Net income (loss) attributable to Dominion		77	113	288	364
Dominion Gas Holdings, LLC | Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total revenue from external customers		0	0	0	0
Net income (loss) attributable to Dominion		$ 6	$ (2)	$ (2)	$ (7)

[1] 2015 amounts have been recast to reflect nonregulated retail energy marketing operations in the Dominion Energy segment.

[2] See Note 17 for amounts attributable to affiliates.

[3] See Note 17 for amounts attributable to related parties.