Edgar Filing: DOMINION RESOURCES INC /VA/

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 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

¨	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.

Virginia Electric and Power Company

Dominion Gas Holdings, LLC

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

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


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

NO_x		Nitrogen oxide

North Carolina Commission		North Carolina Utilities Commission

NRC		Nuclear Regulatory Commission


Abbreviation or Acronym		Definition

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

NSPS		New Source Performance Standards

NYSE		New York Stock Exchange

Ohio Commission		Public Utilities Commission of Ohio

Order 1000		Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development

PIPP		Percentage of Income Payment Plan deployed by East Ohio

PIR		Pipeline Infrastructure Replacement program deployed by East Ohio

PJM		PJM Interconnection, L.L.C.

ppb		Parts-per-billion

PREP		Pipeline Replacement and Expansion Program, a program of replacing, upgrading and expanding natural gas utility infrastructure 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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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

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

California

Alamo

May 2015

April 2015

EDF Renewable Development, Inc.

California

Cottonwood⁽³⁾

106

May 2015

June 2015

EDF Renewable Development, Inc.

California

Catalina 2

July 2015

SunPeak Solar, LLC

California

Imperial Valley 2

August 2015

(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.

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.

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.

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	)


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	)


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

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

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.

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


	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.


	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.

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

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	)

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	)

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

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.

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.

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


	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.

(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

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.

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

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.

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.

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.

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

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 have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. While the impacts of this rule could be material to Dominion’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.

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

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.

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.

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.

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.

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.

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 $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

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;

•

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.

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.

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;

•

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.

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.

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.

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 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.

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:

•

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.

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).

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

•

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.

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

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

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.

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.

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.

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.

100

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.

101

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.

102

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