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, 2015

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

For the transition period from to


Commission File Number	Exact name of registrants as specified in their charters, address of principal executive offices and registrants’ telephone number	I.R.S. Employer Identification Number
001-08489	DOMINION RESOURCES, INC.	54-1229715
000-55337	VIRGINIA ELECTRIC AND POWER COMPANY	54-0418825
000-55338	DOMINION GAS HOLDINGS, LLC	46-3639580

	120 Tredegar Street Richmond, Virginia 23219 (804) 819-2000

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

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


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

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


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

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

Dominion Resources, Inc.

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 September 30, 2015, the latest practicable date for determination, Dominion Resources, Inc. had 595,333,610 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		80
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		94
Item 4.	Controls and Procedures		96

	PART II. Other Information

Item 1.	Legal Proceedings		97
Item 1A.	Risk Factors		97
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		97
Item 6.	Exhibits		99

GLOSSARY OF TERMS

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


Abbreviation or Acronym		Definition
2013 Equity Units		Dominion’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013

2014 Equity Units		Dominion’s 2014 Series A Equity Units issued in July 2014

AFUDC		Allowance for funds used during construction

AOCI		Accumulated other comprehensive income (loss)

AROs		Asset retirement obligations

ARP		Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the CAA

ATEX line		Appalachia to Texas Express ethane line

Atlantic Coast Pipeline		Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion, Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc.

BACT		Best available control technology

bcf		Billion cubic feet

Blue Racer		Blue Racer Midstream, LLC, a joint venture between Dominion and Caiman

BOD		Board of Directors

BP		BP Wind Energy North America Inc.

BREDL		Blue Ridge Environmental Defense League

Bremo		Bremo power station

Brunswick County		A 1,358 MW combined cycle, natural gas-fired power station under construction in Brunswick County, Virginia

CAA		Clean Air Act

Caiman		Caiman Energy II, LLC

CAIR		Clean Air Interstate Rule

CAISO		California independent system operator

CCR		Coal combustion residual

CEO		Chief Executive Officer

CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund

CFO		Chief Financial Officer

Chesapeake		Chesapeake power station

CO₂		Carbon dioxide

COL		Combined Construction Permit and Operating License

Companies		Dominion, Virginia Power and Dominion Gas, collectively

Cooling degree days		Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day

Cove Point		Dominion Cove Point LNG, LP

CPCN		Certificate of Public Convenience and Necessity

CSAPR		Cross State Air Pollution Rule

CWA		Clean Water Act

D.C.		District of Columbia

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 holds a 24.72% 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


Abbreviation or Acronym		Definition
Dominion NGL Pipelines, LLC		The initial owner of the 58-mile G-150 pipeline project, which is designed to transport approximately 27,000 barrels per day of NGLs from Natrium to an interconnect with the ATEX line of Enterprise near Follansbee, West Virginia

DRS		Dominion Resources Services, Inc.

DSM		Demand-side management

Dth		Dekatherm

DTI		Dominion Transmission, Inc.

DVP		Dominion Virginia Power operating segment

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

Enterprise		Enterprise Product Partners, L.P.

EPA		Environmental Protection Agency

EPC		Engineering, procurement and construction

EPS		Earnings per share

FERC		Federal Energy Regulatory Commission

Four Brothers		Four Brothers Solar, LLC, a limited liability company owned by Dominion and Four Brothers Holdings, LLC, a wholly-owned subsidiary of SunEdison

Fowler Ridge		A wind-turbine facility joint venture between Dominion and BP in Benton County, Indiana

FTRs		Financial transmission rights

GAAP		U.S. generally accepted accounting principles

Gal		Gallon

GHG		Greenhouse gas

Granite Mountain		Granite Mountain Holdings, LLC, a limited liability company owned by Dominion and Granite Mountain Renewables, LLC, a wholly-owned subsidiary of SunEdison

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

INPO		Institute of Nuclear Power Operations

IRCA		Intercompany revolving credit agreement

Iron Springs		Iron Springs Holdings, LLC, a limited liability company owned by Dominion and Iron Springs Renewables, LLC, a wholly-owned subsidiary of SunEdison

Iroquois		Iroquois Gas Transmission System L.P.

ISO		Independent system operator

ISO-NE		ISO New England

Kewaunee		Kewaunee nuclear power station

Keys Energy Project		Project to provide 107,000 Dths/day of firm transportation service from Cove Point’s interconnect with Transco in Fairfax County, Virginia to Keys Energy Center, LLC’s power generating facility in Prince George’s County, Maryland

kV		Kilovolt

LNG		Liquefied natural gas

MATS		Utility Mercury and Air Toxics Standard Rule

MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations

MGD		Million gallons a day

Millstone		Millstone nuclear power station

MISO		Midcontinent Independent Transmission System Operator, Inc.

Moody’s		Moody’s Investors Service

Morgans Corner		Morgans Corner Solar Energy, LLC

MW		Megawatt

MWh		Megawatt hour

Natrium		A natural gas and fractionation facility located in Natrium, West Virginia, owned by Blue Racer

NCEMC		North Carolina Electric Membership Corporation

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

NG		Collectively, North East Transmission Co., Inc. and National Grid IGTS Corp.

NGLs		Natural gas liquids


Abbreviation or Acronym		Definition
NJNR		NJNR Pipeline Company

North Anna		North Anna nuclear power station

North Carolina Commission		North Carolina Utilities Commission

Northern System		Collection of approximately 131 miles of various diameter natural gas pipelines in Ohio

NO_x		Nitrogen oxide

NRC		Nuclear Regulatory Commission

NSPS		New Source Performance Standards

NYSE		New York Stock Exchange

ODEC		Old Dominion Electric Cooperative

Ohio Commission		Public Utilities Commission of Ohio

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

PIPP		Percentage of Income Payment Plan deployed by East Ohio

PJM		PJM Interconnection, L.L.C.

Possum Point		Possum Point power station

ppb		Parts-per-billion

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

PSD		Prevention of Significant Deterioration

PSMP		Pipeline Safety and Management Program to be deployed by East Ohio to ensure the continued safe and reliable operation of East Ohio’s system and compliance with pipeline safety laws

REIT		Real estate investment trust

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

Rider US-1		A rate adjustment clause associated with the recovery of costs related to Remington Solar Facility

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

RTO		Regional transmission organization

SEC		Securities and Exchange Commission

SELC		Southern Environmental Law Center

Shell		Shell WindEnergy, Inc.

SO₂		Sulfur dioxide

St. Charles Transportation Project		Project to provide 132,000 Dths/day of firm transportation service from Cove Point’s interconnect with Transco in Fairfax County, Virginia to Competitive Power Venture Maryland, LLC’s power generating facility in Charles County, Maryland

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

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

Three Cedars		Granite Mountain and Iron Springs, collectively

U.S.		United States of America

UAO		Unilateral Administrative Order

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

Yorktown		Yorktown power station

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,
	2015		2014		2015		2014
(millions, except per share amounts)
Operating Revenue	$	2,971	$	3,050	$	9,127	$	9,493

Operating Expenses
Electric fuel and other energy-related purchases		636		743		2,180		2,710
Purchased electric capacity		75		86		259		261
Purchased gas		85		209		446		1,073
Other operations and maintenance		564		614		1,875		1,972
Depreciation, depletion and amortization		355		354		1,037		970
Other taxes		133		123		432		424

Total operating expenses		1,848		2,129		6,229		7,410

Income from operations		1,123		921		2,898		2,083

Other income		11		69		127		166
Interest and related charges		230		231		674		695

Income from operations including noncontrolling interests before income tax expense		904		759		2,351		1,554
Income tax expense		305		228		794		477

Net Income Including Noncontrolling Interests		599		531		1,557		1,077
Noncontrolling Interests		6		2		15		10

Net Income Attributable to Dominion	$	593	$	529	$	1,542	$	1,067

Earnings Per Common Share
Net income attributable to Dominion - Basic	$	1.00	$	0.91	$	2.61	$	1.83
Net income attributable to Dominion - Diluted		1.00		0.90		2.60		1.83
Dividends declared per common share		0.6475		0.6000		1.9425		1.8000

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,
	2015			2014			2015			2014
(millions)
Net income including noncontrolling interests	$	599		$	531		$	1,557		$	1,077
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities⁽¹⁾		(7	)		(58	)		25			(267	)
Changes in unrealized net gains (losses) on investment securities⁽²⁾		(59	)		2			(55	)		80
Changes in unrecognized pension and other postretirement benefit costs⁽³⁾		(9	)		—			(6	)		—
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities⁽⁴⁾		(53	)		(31	)		(53	)		113
Net realized gains on investment securities⁽⁵⁾		(2	)		(21	)		(35	)		(39	)
Net pension and other postretirement benefit costs⁽⁶⁾		14			8			39			25
Changes in other comprehensive income (loss) from equity method investees⁽⁷⁾		1			—			—			(5	)

Total other comprehensive loss		(115	)		(100	)		(85	)		(93	)

Comprehensive income including noncontrolling interests		484			431			1,472			984
Comprehensive income attributable to noncontrolling interests		6			2			15			10

Comprehensive income attributable to Dominion	$	478		$	429		$	1,457		$	974

(1)	Net of $— million and $36 million tax for the three months ended September 30, 2015 and 2014, respectively, and net of $(20) million and $163 million tax for the nine months ended September 30, 2015 and 2014, respectively.

(2)	Net of $55 million and $(2) million tax for the three months ended September 30, 2015 and 2014, respectively, and net of $50 million and $(30) million tax for the nine months ended September 30, 2015 and 2014, respectively.

(3)	Net of $(9) million and $— million tax for the three months ended September 30, 2015 and 2014, respectively, and net of $(6) million and $— million tax for the nine months ended September 30, 2015 and 2014, respectively.

(4)	Net of $30 million and $22 million tax for the three months ended September 30, 2015 and 2014, respectively, and net of $34 million and $(72) million tax for the nine months ended September 30, 2015 and 2014, respectively.

(5)	Net of $— million and $13 million tax for the three months ended September 30, 2015 and 2014, respectively, and net of $20 million and $24 million tax for the nine months ended September 30, 2015 and 2014, respectively.

(6)	Net of $(7) million and $(6) million tax for the three months ended September 30, 2015 and 2014, respectively, and net of $(25) million and $(18) million tax for the nine months ended September 30, 2015 and 2014, respectively.

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

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

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30, 2015			December 31, 2014⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	238		$	318
Customer receivables (less allowance for doubtful accounts of $36 and $34)		1,289			1,514
Other receivables (less allowance for doubtful accounts of $2 and $3)		144			119
Inventories		1,310			1,410
Prepayments		142			167
Derivative assets		243			536
Deferred income taxes		288			800
Other		469			751

Total current assets		4,123			5,615

Investments
Nuclear decommissioning trust funds		4,033			4,196
Investment in equity method affiliates		1,322			1,081
Other		269			284

Total investments		5,624			5,561

Property, Plant and Equipment
Property, plant and equipment		55,848			51,406
Accumulated depreciation, depletion and amortization		(16,067	)		(15,136	)

Total property, plant and equipment, net		39,781			36,270

Deferred Charges and Other Assets
Goodwill		3,294			3,044
Pension and other postretirement benefit assets		1,025			956
Regulatory assets		1,593			1,642
Other		1,159			1,239

Total deferred charges and other assets		7,071			6,881

Total assets	$	56,599		$	54,327

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

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

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


	September 30, 2015			December 31, 2014⁽¹⁾
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	1,528		$	1,375
Short-term debt		2,555			2,775
Accounts payable		705			952
Accrued interest, payroll and taxes		553			566
Other⁽²⁾		1,405			1,530

Total current liabilities		6,746			7,198

Long-Term Debt
Long-term debt		19,790			18,348
Junior subordinated notes		1,370			1,374
Remarketable subordinated notes		2,085			2,083

Total long-term debt		23,245			21,805

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		7,551			7,444
Asset retirement obligations		1,824			1,633
Regulatory liabilities		2,173			1,991
Other		1,784			2,299

Total deferred credits and other liabilities		13,332			13,367

Total liabilities		43,323			42,370

Commitments and Contingencies (see Note 16)
Equity
Common stock – no par⁽³⁾		6,606			5,876
Retained earnings		6,487			6,095
Accumulated other comprehensive loss		(501	)		(416	)

Total common shareholders’ equity		12,592			11,555

Noncontrolling interests		684			402

Total equity		13,276			11,957

Total liabilities and equity	$	56,599		$	54,327

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

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

(3)	1 billion shares authorized; 595 million shares and 585 million shares outstanding at September 30, 2015 and December 31, 2014, respectively.

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,	2015			2014
(millions)
Operating Activities
Net income including noncontrolling interests	$	1,557		$	1,077

Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)		1,250			1,171
Deferred income taxes and investment tax credits		703			444
Gains on the sale of assets and businesses		(123	)		(160	)
Charges associated with North Anna and offshore wind legislation		—			330
Other adjustments		(1	)		(104	)
Changes in:
Accounts receivable		229			300
Inventories		(3	)		(39	)
Deferred fuel and purchased gas costs, net (including write-off)		70			(252	)
Prepayments		45			14
Accounts payable		(222	)		(291	)
Accrued interest, payroll and taxes		(13	)		(9	)
Margin deposit assets and liabilities		205			55
Other operating assets and liabilities		(244	)		(126	)

Net cash provided by operating activities		3,453			2,410

Investing Activities
Plant construction and other property additions (including nuclear fuel)		(3,632	)		(3,742	)
Acquisition of solar development projects		(278	)		(66	)
Acquisition of DCG		(497	)		—
Proceeds from sales of securities		937			1,524
Purchases of securities		(921	)		(1,562	)
Proceeds from the sale of electric retail energy marketing business		—			187
Proceeds from the sale of assets to Blue Racer		—			86
Proceeds from assignments of shale development rights		80			—
Other		(39	)		40

Net cash used in investing activities		(4,350	)		(3,533	)

Financing Activities
Issuance (repayment) of short-term debt, net		(220	)		702
Issuance of long-term debt		2,262			2,150
Repayment and repurchase of long-term debt		(675	)		(725	)
Subsidiary preferred stock redemption		—			(125	)
Issuance of common stock		717			138
Common dividend payments		(1,150	)		(1,048	)
Subsidiary preferred dividend payments		—			(9	)
Other		(117	)		(58	)

Net cash provided by financing activities		817			1,025

Decrease in cash and cash equivalents		(80	)		(98	)
Cash and cash equivalents at beginning of period		318			316

Cash and cash equivalents at end of period	$	238		$	218

Supplemental Cash Flow Information
Significant noncash investing activities:⁽¹⁾
Accrued capital expenditures	$	389		$	309
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.

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,
	2015		2014		2015		2014
(millions)
Operating Revenue⁽¹⁾	$	2,058	$	2,053	$	6,008	$	5,765

Operating Expenses
Electric fuel and other energy-related purchases⁽¹⁾		554		649		1,861		1,817
Purchased electric capacity		75		86		259		261
Other operations and maintenance:
Affiliated suppliers		64		70		208		211
Other		311		331		1,008		1,164
Depreciation and amortization		244		260		713		695
Other taxes		69		63		212		205

Total operating expenses		1,317		1,459		4,261		4,353

Income from operations		741		594		1,747		1,412

Other income		13		24		49		60
Interest and related charges		116		101		332		311

Income before income tax expense		638		517		1,464		1,161
Income tax expense		253		203		564		454

Net Income		385		314		900		707
Preferred dividends		—		2		—		10

Balance available for common stock	$	385	$	312	$	900	$	697

(1)	See Note 18 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,
	2015			2014			2015			2014
(millions)
Net income	$	385		$	314		$	900		$	707
Other comprehensive income (loss), net of taxes:
Net deferred losses on derivatives-hedging activities⁽¹⁾		(6	)		(1	)		(3	)		—
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds⁽²⁾		(11	)		2			(10	)		10
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities⁽³⁾		—			1			1			(3	)
Net realized gains on nuclear decommissioning trust funds⁽⁴⁾		(1	)		(3	)		(4	)		(5	)

Other comprehensive income (loss)		(18	)		(1	)		(16	)		2

Comprehensive income	$	367		$	313		$	884		$	709

(1)	Net of $3 million and $— million tax for the three months ended September 30, 2015 and 2014, respectively, and net of $1 million and $— million tax for the nine months ended September 30, 2015 and 2014, respectively.

(2)	Net of $5 million and $(1) million tax for the three months ended September 30, 2015 and 2014, respectively, and net of $5 million and $(6) million tax for the nine months ended September 30, 2015 and 2014, respectively.

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

(4)	Net of $2 million tax for both the three months ended September 30, 2015 and 2014, and net of $3 million tax for both the nine months ended September 30, 2015 and 2014.

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, 2015			December 31, 2014⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	39		$	15
Customer receivables (less allowance for doubtful accounts of $27 and $25)		955			986
Other receivables (less allowance for doubtful accounts of $1 at both dates)		96			65
Inventories (average cost method)		842			853
Prepayments		24			252
Regulatory assets		328			298
Other⁽²⁾		43			82

Total current assets		2,327			2,551

Investments
Nuclear decommissioning trust funds		1,875			1,930
Other		3			4

Total investments		1,878			1,934

Property, Plant and Equipment
Property, plant and equipment		37,016			35,180
Accumulated depreciation and amortization		(11,622	)		(11,080	)

Total property, plant and equipment, net		25,394			24,100

Deferred Charges and Other Assets
Regulatory assets		422			439
Other⁽²⁾		538			485

Total deferred charges and other assets		960			924

Total assets	$	30,559		$	29,509

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

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

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

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


	September 30, 2015		December 31, 2014⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	677	$	211
Short-term debt		1,362		1,361
Accounts payable		372		458
Payables to affiliates		59		92
Affiliated current borrowings		—		427
Accrued interest, payroll and taxes		336		199
Other⁽²⁾		666		528

Total current liabilities		3,472		3,276

Long-Term Debt		8,952		8,726

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		4,323		4,415
Asset retirement obligations		1,030		848
Regulatory liabilities		1,822		1,683
Other⁽²⁾		436		506

Total deferred credits and other liabilities		7,611		7,452

Total liabilities		20,035		19,454

Commitments and Contingencies (see Note 16)
Common Shareholder’s Equity
Common stock – no par⁽³⁾		5,738		5,738
Other paid-in capital		1,113		1,113
Retained earnings		3,639		3,154
Accumulated other comprehensive income		34		50

Total common shareholder’s equity		10,524		10,055

Total liabilities and shareholder’s equity	$	30,559	$	29,509

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

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

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

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,	2015			2014
(millions)
Operating Activities
Net income	$	900		$	707
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		844			824
Deferred income taxes and investment tax credits		9			235
Charges associated with North Anna and offshore wind legislation		—			330
Other adjustments		20			(28	)
Changes in:
Accounts receivable		10			20
Inventories		11			(33	)
Prepayments		228			11
Deferred fuel expenses, net (including write-off)		40			(284	)
Accounts payable		(62	)		(24	)
Accrued interest, payroll and taxes		137			60
Other operating assets and liabilities		37			(98	)

Net cash provided by operating activities		2,174			1,720

Investing Activities
Plant construction and other property additions		(1,840	)		(2,120	)
Purchases of nuclear fuel		(100	)		(140	)
Proceeds from sales of securities		407			415
Purchases of securities		(423	)		(421	)
Other		(38	)		(18	)

Net cash used in investing activities		(1,994	)		(2,284	)

Financing Activities
Issuance of short-term debt, net		1			562
Repayment of affiliated current borrowings, net		(427	)		(80	)
Issuance of long-term debt		1,112			750
Repayment of long-term debt		(421	)		(52	)
Preferred stock redemption		—			(125	)
Common dividend payments		(416	)		(466	)
Preferred dividend payments		—			(9	)
Other		(5	)		(11	)

Net cash provided by (used in) financing activities		(156	)		569

Increase in cash and cash equivalents		24			5
Cash and cash equivalents at beginning of period		15			16

Cash and cash equivalents at end of period	$	39		$	21

Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	139		$	176

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,
	2015		2014		2015		2014
(millions)
Operating Revenue⁽¹⁾	$	365	$	391	$	1,291	$	1,388

Operating Expenses
Purchased gas⁽¹⁾		8		34		103		247
Other energy-related purchases		4		8		17		29
Other operations and maintenance:
Affiliated suppliers		12		12		50		49
Other⁽²⁾		51		79		211		204
Depreciation and amortization		53		50		157		146
Other taxes		35		31		127		117

Total operating expenses		163		214		665		792

Income from operations		202		177		626		596

Other income		4		5		17		18
Interest and related charges		18		7		53		19

Income from operations before income taxes		188		175		590		595
Income tax expense		77		68		233		231

Net Income	$	111	$	107	$	357	$	364

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

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

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,
	2015			2014			2015			2014
(millions)
Net income	$	111		$	107		$	357		$	364
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities⁽¹⁾		3			(7	)		2			(33	)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities⁽²⁾		(2	)		4			(3	)		11
Net pension and other postretirement benefit costs⁽³⁾		1			1			3			3

Other comprehensive income (loss)		2			(2	)		2			(19	)

Comprehensive income	$	113		$	105		$	359		$	345

(1)	Net of $(1) million and $4 million tax for the three months ended September 30, 2015 and 2014, respectively, and net of $— million and $22 million tax for the nine months ended September 30, 2015 and 2014, respectively.

(2)	Net of $1 million million and $(2) million tax for the three months ended September 30, 2015 and 2014, respectively, and net of $1 million and $(7) million tax for the nine months ended September 30, 2015 and 2014, respectively.

(3)	Net of $(1) million tax for both the three months ended September 30, 2015 and 2014, and net of $(3) million and $(2) million tax for the nine months ended September 30, 2015 and 2014, respectively.

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

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30, 2015			December 31, 2014⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	18		$	9
Customer receivables (less allowance for doubtful accounts of $5 and $4)⁽²⁾		180			322
Other receivables (less allowance for doubtful accounts of $1 at both dates)⁽²⁾		11			19
Affiliated receivables		6			12
Inventories		80			65
Prepayments		42			166
Other⁽²⁾		141			217

Total current assets		478			810

Investments		100			108

Property, Plant and Equipment
Property, plant and equipment		9,429			8,902
Accumulated depreciation and amortization		(2,641	)		(2,538	)

Total property, plant and equipment, net		6,788			6,364

Deferred Charges and Other Assets
Goodwill		542			542
Pension and other postretirement benefit assets⁽²⁾		1,577			1,486
Other⁽²⁾		540			538

Total deferred charges and other assets		2,659			2,566

Total assets	$	10,025		$	9,848

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

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

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

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


	September 30, 2015			December 31, 2014⁽¹⁾
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Short-term debt	$	382		$	—
Accounts payable		139			247
Payables to affiliates		13			41
Affiliated current borrowings		198			384
Accrued interest, payroll and taxes		149			194
Other⁽²⁾		160			172

Total current liabilities		1,041			1,038

Long-Term Debt		2,595			2,594

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,222			2,158
Other⁽²⁾		486			492

Total deferred credits and other liabilities		2,708			2,650

Total liabilities		6,344			6,282

Commitments and Contingencies (see Note 16)
Equity
Membership interests		3,765			3,652
Accumulated other comprehensive loss⁽²⁾		(84	)		(86	)

Total equity		3,681			3,566

Total liabilities and equity	$	10,025		$	9,848

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

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

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

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


Nine Months Ended September 30,	2015			2014
(millions)
Operating Activities
Net income	$	357		$	364
Adjustments to reconcile net income to net cash provided by operating activities:
Gains on sales of assets		(123	)		(64	)
Depreciation and amortization		157			146
Deferred income taxes and investment tax credits		75			80
Other adjustments		4			(12	)
Changes in:
Accounts receivable		150			60
Deferred purchased gas costs, net		19			33
Prepayments		145			29
Inventories		(15	)		(28	)
Accounts payable		(112	)		(113	)
Payables to affiliates		(28	)		(8	)
Accrued interest, payroll and taxes		(45	)		(56	)
Other operating assets and liabilities		(88	)		(83	)

Net cash provided by operating activities		496			348

Investing Activities
Plant construction and other property additions		(514	)		(467	)
Proceeds from sale of assets to an affiliate		—			47
Proceeds from assignments of shale development rights		80			—
Other		(5	)		(1	)

Net cash used in investing activities		(439	)		(421	)

Financing Activities
Issuance of short-term debt, net		382			—
Issuance (repayment) of affiliated current borrowings, net		(186	)		288
Distribution payments		(244	)		(206	)
Other		—			(1	)

Net cash provided by (used in) financing activities		(48	)		81

Increase in cash and cash equivalents		9			8
Cash and cash equivalents at beginning of period		9			8

Cash and cash equivalents at end of period	$	18		$	16

Supplemental Cash Flow Information
Significant noncash investing and financing activities:
Accrued capital expenditures	$	46		$	63
Extinguishment of affiliated long-term debt in exchange for assets sold to affiliate		—			67

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

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.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the SEC, the Companies’ accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with GAAP. These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.

In the Companies’ opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position as of September 30, 2015, their results of operations for the three and nine months ended September 30, 2015 and 2014, and their cash flows for the nine months ended September 30, 2015 and 2014. Such adjustments are normal and recurring in nature unless otherwise noted.

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

The Companies’ accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. As of September 30, 2015, Dominion owns the general partner and 63.1% 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, 2015, Dominion owns 50% of the units in and consolidates Four Brothers and Three Cedars. SunEdison’s ownership interest in these projects is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. See Note 3 for more details regarding the nature and purpose of Four Brothers and Three Cedars.

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

Certain amounts in the Companies’ 2014 Consolidated Financial Statements and Notes have been reclassified to conform to the 2015 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

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

Note 3. Acquisitions and Dispositions

Dominion

Wholly-Owned Merchant Solar Projects

Acquisitions

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


Completed Acquisition Date	Seller	Number of Projects	Project Location		Project Name(s)	Initial Acquisition Cost (millions)⁽¹⁾		Project Cost (millions)⁽²⁾		Date of Commercial Operations	MW Capacity
March 2014	Recurrent Energy Development Holdings, LLC	6		California	Camelot, Kansas, Kent South, Old River One, Adams East, Columbia 2	$	50	$	428	Fourth quarter 2014		139

November 2014	CSI Project Holdco, LLC	1		California	West Antelope		79		79	November 2014		20

December 2014	EDF Renewable Development, Inc.	1		California	CID		71		71	January 2015		20

April 2015	EC&R NA Solar PV, LLC	1		California	Alamo		66		66	May 2015		20

April 2015	EDF Renewable Development, Inc.	3		California	City of Corcoran, Goose Lake, Marin Carport⁽³⁾		106		109	May 2015		24

June 2015	EDF Renewable Development, Inc.	1		California	Catalina 2		68		68	July 2015		18

July 2015	SunPeak Solar, LLC	1		California	Imperial Valley 2		42		69	August 2015		20

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

(2)	Includes acquisition cost.

(3)	Marin Carport is expected to begin commercial operations in 2016.

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

Expected 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 currently wholly-owned merchant solar projects to SunEdison for approximately $300 million. The potential sale relates to a total of 24 solar projects totaling approximately 425 MW. The sales of these interests are expected to close by the end of the first quarter of 2016.

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 approximately $64 million of consideration, consisting of $2 million in cash and a $62 million payable. As of September 30, 2015, a $56 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Four Brothers’ purpose is to develop and operate four solar projects located in Utah, which will produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $730 million to construct, including the initial acquisition cost. Dominion is obligated to contribute $445 million of capital to fund the construction of the projects. As of September 30, 2015, Dominion has contributed approximately $38 million. The facilities are expected to begin commercial operations in the third quarter of 2016, generating approximately 320 MW.

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

Long-term power purchase, interconnection and operation and maintenance agreements have been executed for both Four Brothers and Three Cedars. Dominion expects to 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 approximately $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 approximately $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.

Four Brothers and Three Cedars have entered into agreements with SunEdison to provide administrative and support services in connection with the construction of the projects, operation and maintenance of the facilities, and administrative and technical management services of the solar facilities. In addition, Dominion has entered into contracts with SunEdison to provide services related to construction project management and oversight. Costs related to services to be provided under these agreements were immaterial for the nine months ended September 30, 2015.

Dominion Midstream Acquisition of Interest in Iroquois

In September 2015, Dominion Midstream acquired from NG and NJNR a 25.93% noncontrolling partnership interest in Iroquois, which owns and operates a 416-mile, FERC-regulated natural gas transmission pipeline in New York and Connecticut. In exchange for this partnership interest, Dominion Midstream issued approximately 8.6 million common units representing limited partnership interests in Dominion Midstream (approximately 6.8 million common units to NG for its 20.4% interest and approximately 1.8 million common units to NJNR for its 5.53% interest). The investment was recorded at approximately $216 million based on the value of Dominion Midstream’s common units at closing. These common units are reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. Dominion Midstream’s noncontrolling partnership interest is reflected in the Dominion Energy operating segment. In addition to this acquisition, Dominion Gas currently holds a 24.72% partnership interest in Iroquois. Dominion Midstream and Dominion Gas each account for their interest in Iroquois as an equity method investment. See Notes 10 and 14 for more information regarding Iroquois.

Acquisition of DCG

In January 2015, Dominion completed the acquisition of 100% of the equity interests of DCG from SCANA Corporation for approximately $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 approximately $277 million of net property, plant and equipment, $250 million of goodwill, of which approximately $225 million is expected to be deductible for income tax purposes, and approximately $38 million of regulatory liabilities. The goodwill reflects the value associated with enhancing Dominion’s regulated gas position, economic value attributable to future expansion projects as well as increased opportunities for synergies. The acquired assets of 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, approximately $301 million senior unsecured promissory note payable by Dominion Midstream at an annual interest rate of 0.6%, and 5,112,139 common units, valued at $200 million, representing limited partner interests in Dominion Midstream. The number of units was based on the volume weighted average trading price of Dominion Midstream’s common units for the ten trading days prior to April 1, 2015, or $39.12 per unit. Since Dominion consolidates Dominion Midstream for financial reporting purposes, this transaction was eliminated upon consolidation and did not impact Dominion’s financial position or cash flows.

Sale of Electric Retail Energy Marketing Business

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

Virginia Power

Acquisition of Solar Project

In September 2015, Virginia Power entered into an agreement to acquire 100% of a solar development project in North Carolina from Morgans Corner for approximately $47 million. The acquisition is expected to close in the fourth quarter of 2015. The project is expected to be placed into service by the end of the first quarter of 2016 and cost approximately $50 million once constructed, including the initial acquisition cost. Upon completion, the facility is expected to generate approximately 20 MW. The output generated by Morgans Corner will be used to meet a ten year non-jurisdictional supply agreement with the U.S. Navy, which has the unilateral option to extend for an additional ten years. In October 2015, the North Carolina Commission granted the transfer of the existing CPCN from Morgans Corner to Virginia Power. The acquired assets will be included in the Virginia Power Generation operating segment.

Dominion Gas

Assignments of Shale Development Rights

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

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

In September 2015, DTI 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 DTI, subject to customary adjustments, of approximately $52 million and an overriding royalty interest in gas produced from the acreage. In September 2015, DTI 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.

Dominion and Dominion Gas

Blue Racer

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

Note 4. Operating Revenue

The Companies’ operating revenue consists of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
(millions)
Dominion
Electric sales:
Regulated	$	2,020	$	2,026	$	5,911	$	5,674
Nonregulated		388		353		1,145		1,527
Gas sales:
Regulated		21		25		168		242
Nonregulated		66		187		361		532
Gas transportation and storage		365		343		1,221		1,138
Other		111		116		321		380

Total operating revenue	$	2,971	$	3,050	$	9,127	$	9,493

Virginia Power
Regulated electric sales	$	2,020	$	2,026	$	5,911	$	5,674
Other		38		27		97		91

Total operating revenue	$	2,058	$	2,053	$	6,008	$	5,765

Dominion Gas
Gas sales:
Regulated	$	9	$	15	$	87	$	152
Nonregulated		1		3		5		16
Gas transportation and storage		302		296		1,035		996
NGL revenue		20		54		71		155
Other		33		23		93		69

Total operating revenue	$	365	$	391	$	1,291	$	1,388

Note 5. Income Taxes

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


	Dominion						Virginia Power						Dominion Gas
Nine Months Ended September 30,	2015			2014			2015			2014			2015			2014
U.S. statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		4.0			2.7			4.2			3.9			4.1			3.7
Investment tax credits		(3.5	)		(6.0	)		—			—			—			—
Production tax credits		(0.8	)		(1.1	)		(0.5	)		(0.6	)		—			—
Other, net		(0.9	)		0.1			(0.2	)		0.8			0.4			0.1

Effective tax rate		33.8	%		30.7	%		38.5	%		39.1	%		39.5	%		38.8	%

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

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,
	2015		2014		2015		2014
(millions, except EPS)
Net income attributable to Dominion	$	593	$	529	$	1,542	$	1,067

Average shares of common stock outstanding – Basic		594.6		583.1		591.3		582.2
Net effect of dilutive securities⁽¹⁾		0.9		1.5		1.4		1.6

Average shares of common stock outstanding – Diluted		595.5		584.6		592.7		583.8

Earnings Per Common Share – Basic	$	1.00	$	0.91	$	2.61	$	1.83
Earnings Per Common Share – Diluted	$	1.00	$	0.90	$	2.60	$	1.83

(1)

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

The 2014 Equity Units are potentially dilutive securities but were excluded from the calculation of diluted EPS for the three and nine months ended September 30, 2015 and 2014, 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, 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	)

Three Months Ended September 30, 2014
Beginning balance	$	(353	)	$	534		$	(493	)	$	(5	)	$	(317	)
Other comprehensive income before reclassifications: gains (losses)		(58	)		2			—			—			(56	)
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(31	)		(21	)		8			—			(44	)

Net current-period other comprehensive income (loss)		(89	)		(19	)		8			—			(100	)

Ending balance	$	(442	)	$	515		$	(485	)	$	(5	)	$	(417	)

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	)

Nine Months Ended September 30, 2014
Beginning balance	$	(288	)	$	474		$	(510	)	$	—		$	(324	)
Other comprehensive income before reclassifications: gains (losses)		(267	)		80			—			(5	)		(192	)
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		113			(39	)		25			—			99

Net current-period other comprehensive income (loss)		(154	)		41			25			(5	)		(93	)

Ending balance	$	(442	)	$	515		$	(485	)	$	(5	)	$	(417	)

(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, 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

Three Months Ended September 30, 2014
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(66	)	Operating revenue
		3		Purchased gas
		5		Electric fuel and other energy-related purchases
Interest rate contracts		5		Interest and related charges

		(53	)
Tax		22		Income tax expense

	$	(31	)

Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(38	)	Other income
Impairment		4		Other income

		(34	)
Tax		13		Income tax expense

	$	(21	)

Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(4	)	Other operations and maintenance
Actuarial (gains) losses		18		Other operations and maintenance

		14
Tax		(6	)	Income tax expense

	$	8

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

Nine Months Ended September 30, 2014
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	175		Operating revenue
		7		Purchased gas
		(8	)	Electric fuel and other energy-related purchases
Interest rate contracts		11		Interest and related charges

		185
Tax		(72	)	Income tax expense

	$	113

Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(71	)	Other income
Impairment		8		Other income

		(63	)
Tax		24		Income tax expense

	$	(39	)

Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(9	)	Other operations and maintenance
Actuarial (gains) losses		52		Other operations and maintenance

		43
Tax		(18	)	Income tax expense

	$	25

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, 2015
Beginning balance	$	(22	)	$	(64	)	$	(86	)
Other comprehensive income before reclassifications: gains (losses)		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	)

Three Months Ended September 30, 2014
Beginning balance	$	(16	)	$	(59	)	$	(75	)
Other comprehensive income before reclassifications: gains (losses)		(7	)		—			(7	)
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		4			1			5

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

Ending balance	$	(19	)	$	(58	)	$	(77	)

Nine Months Ended September 30, 2015
Beginning balance	$	(20	)	$	(66	)	$	(86	)
Other comprehensive income before reclassifications: gains (losses)		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	)

Nine Months Ended September 30, 2014
Beginning balance	$	3		$	(61	)	$	(58	)
Other comprehensive income before reclassifications: gains (losses)		(33	)		—			(33	)
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		11			3			14

Net current-period other comprehensive income (loss)		(22	)		3			(19	)

Ending balance	$	(19	)	$	(58	)	$	(77	)

(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, 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

Three Months Ended September 30, 2014
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	1		Operating revenue
		5		Purchased gas

		6
Tax		(2	)	Income tax expense

	$	4

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, 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

Nine Months Ended September 30, 2014
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	8		Operating revenue
		10		Purchased gas

		18
Tax		(7	)	Income tax expense

	$	11

Unrecognized pension and other postretirement benefit costs:
Actuarial (gains) losses	$	5		Other operations and maintenance

		5
Tax		(2	)	Income tax expense

	$	3

Note 8. Fair Value Measurements

The Companies’ fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. See Note 9 in this report for further information about the Companies’ derivatives and hedge accounting activities.

The Companies enter into certain physical and financial forwards, futures, options and swaps, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards and futures contracts. An option model is used to value Level 3 physical and financial options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices, and volumes. For Level 3 fair value measurements, forward market prices, credit spreads and implied price volatilities are considered unobservable. The unobservable inputs are developed and substantiated using historical information, available market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party pricing sources.

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


	Fair Value (millions)		Valuation Techniques	Unobservable Input			Range			Weighted Average⁽¹⁾
Assets:
Physical and Financial Forwards and Futures:
Natural Gas⁽²⁾	$	99	Discounted Cash Flow		Market Price (per Dth)	⁽⁴⁾		(2) - 4			(1	)
					Credit spread	⁽⁵⁾		1% - 6	%		3	%
Liquids⁽³⁾		5	Discounted Cash Flow		Market Price (per Gal)	⁽⁴⁾		0 - 2			1
Electric		4	Discounted Cash Flow		Market Price (per MWh)	⁽⁴⁾		26 - 47			45
FTRs		23	Discounted Cash Flow		Market Price (per MWh)	⁽⁴⁾		(3) - 12			2
Physical and Financial Options:
Natural Gas		6	Option Model		Market Price (per Dth)	⁽⁴⁾		2 - 6			4
					Price Volatility	⁽⁶⁾		23% - 75	%		44	%

Total assets	$	137

Liabilities:
Physical and Financial Forwards and Futures:
Natural Gas⁽²⁾	$	10	Discounted Cash Flow		Market Price (per Dth)	⁽⁴⁾		(2) - 4			1
FTRs		2	Discounted Cash Flow		Market Price (per MWh)	⁽⁴⁾		(12) - 12			1
Physical and Financial Options:
Natural Gas		2	Option Model		Market Price (per Dth)	⁽⁴⁾		2 - 4			3
					Price Volatility	⁽⁶⁾		23% - 50	%		34	%

Total liabilities	$	14

(1)	Averages weighted by volume.

(2)	Includes basis.

(3)	Includes NGLs and oil.

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

(5)	Represents credit spreads unrepresented in published markets.

(6)	Represents volatilities unrepresented in published markets.

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


Significant Unobservable Inputs	Position	Change to Input	Impact on Fair Value Measurement
Market Price	Buy	Increase (decrease)	Gain (loss)
Market Price	Sell	Increase (decrease)	Loss (gain)
Price Volatility	Buy	Increase (decrease)	Gain (loss)
Price Volatility	Sell	Increase (decrease)	Loss (gain)
Credit spread	Asset	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, 2015
Assets:
Derivatives:
Commodity	$	1	$	237	$	137	$	375
Interest rate		—		31		—		31
Investments⁽¹⁾:
Equity securities:
U.S.:
Large cap		2,401		—		—		2,401
Other		5		—		—		5
REIT		59		—		—		59
Non-U.S.:
Large cap		10		—		—		10
Fixed income:
Corporate debt instruments		—		463		—		463
U.S. Treasury securities and agency debentures		431		184		—		615
State and municipal		—		395		—		395
Other		—		97		—		97
Cash equivalents and other		6		1		—		7

Total assets	$	2,913	$	1,408	$	137	$	4,458

Liabilities:
Derivatives:
Commodity	$	1	$	117	$	14	$	132
Interest rate		—		214		—		214

Total liabilities	$	1	$	331	$	14	$	346

At December 31, 2014
Assets:
Derivatives:
Commodity	$	3	$	567	$	125	$	695
Interest rate		—		24		—		24
Investments⁽¹⁾:
Equity securities:
U.S.:
Large cap		2,669		—		—		2,669
Other		6		—		—		6
Non-U.S.:
Large cap		12		—		—		12
Fixed income:
Corporate debt instruments		—		441		—		441
U.S. Treasury securities and agency debentures		419		190		—		609
State and municipal		—		395		—		395
Other		—		74		—		74
Cash equivalents and other		3		10		—		13

Total assets	$	3,112	$	1,701	$	125	$	4,938

Liabilities:
Derivatives:
Commodity	$	3	$	571	$	18	$	592
Interest rate		—		202		—		202

Total liabilities	$	3	$	773	$	18	$	794

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

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,
	2015			2014			2015			2014
(millions)
Beginning balance	$	71		$	3		$	107		$	(16	)
Total realized and unrealized gains (losses):
Included in earnings		(9	)		(2	)		1			98
Included in other comprehensive income (loss)		5			4			(7	)		7
Included in regulatory assets/liabilities		47			39			18			53
Settlements		10			5			1			(94	)
Transfers out of Level 3⁽¹⁾		(1	)		(2	)		3			(1	)

Ending balance	$	123		$	47		$	123		$	47

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		$	1		$	2

(1)

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

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


	Operating revenue			Purchased Gas			Electric fuel and other energy- related purchases			Total
(millions)
Three Months Ended 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

Three Months Ended September 30, 2014
Total gains (losses) included in earnings	$	3		$	(3	)	$	(2	)	$	(2	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		3			(2	)		—			1

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

Nine Months Ended September 30, 2014
Total gains (losses) included in earnings	$	(7	)	$	(4	)	$	109		$	98
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		4			(2	)		—			2

Virginia Power

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


	Fair Value (millions)		Valuation Techniques		Unobservable Input			Range			Weighted Average⁽¹⁾
Assets:
Physical and Financial Forwards and Futures:
FTRs	$	23		Discounted Cash Flow		Market Price (per MWh)	⁽³⁾		(3) - 12			2
Natural Gas⁽²⁾		93		Discounted Cash Flow		Market Price (per Dth)	⁽³⁾		(2) - 3			(1	)
						Credit spread	⁽⁴⁾		1% - 6	%		3	%
Electric		4		Discounted Cash Flow		Market Price (per MWh)	⁽³⁾		44 - 47			45
Physical and Financial Options:
Natural Gas		2		Discounted Cash Flow		Market Price (per Dth)	⁽³⁾		2 - 6			5
						Price Volatility	⁽⁵⁾		50% - 75	%		66	%

Total assets	$	122

Liabilities:
Physical and Financial Forwards and Futures:
FTRs	$	2		Discounted Cash Flow		Market Price (per MWh)	⁽³⁾		(12) - 12			1

Total liabilities	$	2

(1)	Averages weighted by volume.

(2)	Includes basis.

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

(4)	Represents credit spreads unrepresented in published markets.

(5)	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)
Credit spread	Asset	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, 2015
Assets:
Derivatives:
Commodity	$	—	$	20	$	122	$	142
Interest rate		—		8		—		8
Investments⁽¹⁾:
Equity securities:
U.S. large cap		1,037		—		—		1,037
REIT		59		—				59
Fixed income:
Corporate debt instruments		—		252		—		252
U.S. Treasury securities and agency debentures		164		61		—		225
State and municipal		—		199		—		199
Other		—		30		—		30

Total assets	$	1,260	$	570	$	122	$	1,952

Liabilities:
Derivatives:
Commodity	$	—	$	4	$	2	$	6
Interest rate		—		67		—		67

Total liabilities	$	—	$	71	$	2	$	73

At December 31, 2014
Assets:
Derivatives:
Commodity	$	—	$	7	$	106	$	113
Investments⁽¹⁾:
Equity securities:
U.S. large cap		1,157		—		—		1,157
Fixed income:
Corporate debt instruments		—		250		—		250
U.S. Treasury securities and agency debentures		137		61		—		198
State and municipal		—		211		—		211
Other		—		23		—		23

Total assets	$	1,294	$	552	$	106	$	1,952

Liabilities:
Derivatives:
Commodity	$	—	$	11	$	4	$	15
Interest rate		—		72		—		72

Total liabilities	$	—	$	83	$	4	$	87

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

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,
	2015			2014			2015			2014
(millions)
Beginning balance	$	73		$	7		$	102		$	(7	)
Total realized and unrealized gains (losses):
Included in earnings		(10	)		(2	)		(1	)		109
Included in regulatory assets/liabilities		47			39			18			53
Settlements		10			2			1			(109	)

Ending balance	$	120		$	46		$	120		$	46

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, 2015 and 2014. There were no unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and nine months ended September 30, 2015 and 2014.

Dominion Gas

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

Fair Value
(millions)

Valuation Techniques

Unobservable Input

Range

Weighted
Average⁽¹⁾

Assets:

Physical and Financial Forwards and Futures:

NGLs

Discounted Cash Flow

Market Price (per Gal)

⁽²⁾

0 - 2

Total assets

(1)	Averages weighted by volume.

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

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)

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, 2015
Assets:
Commodity	$	—	$	5	$	4	$	9

Total Assets	$	—	$	5	$	4	$	9
Liabilities:
Commodity	$	—	$	1	$	—	$	1
Interest rate		—		17		—		17

Total liabilities	$	—	$	18	$	—	$	18

At December 31, 2014
Assets:
Commodity	$	—	$	—	$	2	$	2

Total Assets	$	—	$	—	$	2	$	2
Liabilities:
Interest rate	$	—	$	9	$	—	$	9

Total liabilities	$	—	$	9	$	—	$	9

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
(millions)
Beginning balance	$	(1	)	$	(3	)	$	2		$	(6	)
Total realized and unrealized gains (losses):
Included in earnings		—			(1	)		1			(8	)
Included in other comprehensive income (loss)		5			5			(7	)		8
Settlements		—			—			(1	)		7
Transfers out of Level 3⁽¹⁾		—			—			9			—

Ending balance	$	4		$	1		$	4		$	1

(1)

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

The gains and losses included in earnings in the Level 3 fair value category were classified in operating revenue in Dominion Gas’ Consolidated Statements of Income for the three and nine months ended September 30, 2015 and 2014. There were no unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and nine months ended September 30, 2015 and 2014.

Fair Value of Financial Instruments

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


	September 30, 2015				December 31, 2014
	Carrying Amount		Estimated Fair Value⁽¹⁾		Carrying Amount		Estimated Fair Value⁽¹⁾
(millions)
Dominion
Long-term debt, including securities due within one year⁽²⁾⁽³⁾	$	21,318	$	22,923	$	19,723	$	21,881
Junior subordinated notes⁽³⁾		1,370		1,290		1,374		1,396
Remarketable subordinated notes⁽³⁾		2,085		2,214		2,083		2,362

Virginia Power
Long-term debt, including securities due within one year⁽³⁾	$	9,629	$	10,764	$	8,937	$	10,293

Dominion Gas
Long-term debt⁽³⁾	$	2,595	$	2,618	$	2,594	$	2,672

(1)

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

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

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

Note 9. Derivatives and Hedge Accounting Activities

The Companies’ accounting policies and objectives and strategies for using derivative instruments are discussed in Note 2 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. See Note 8 in this report for further information about fair value measurements and associated valuation methods for derivatives.

Derivative assets and liabilities are presented gross on the Companies’ Consolidated Balance Sheets. Dominion’s derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Dominion Gas’ and Virginia Power’s derivative contracts consist of over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a counterparty. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency, or other conditions.

In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and in some cases other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on the Companies’ Consolidated Balance Sheets, as well as letters of credit and other forms of security, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure.

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, 2015						December 31, 2014
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	31	$	—	$	31	$	24	$	—	$	24
Commodity contracts:
Over-the-counter		270		—		270		382		—		382
Exchange		95		—		95		298		—		298

Total derivatives, subject to a master netting or similar arrangement		396		—		396		704		—		704
Total derivatives, not subject to a master netting or similar arrangement		10		—		10		15		—		15

Total	$	406	$	—	$	406	$	719	$	—	$	719


			September 30, 2015								December 31, 2014
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	31	$	29	$	—	$	2	$	24	$	16	$	—	$	8
Commodity contracts:
Over-the-counter		270		16		23		231		382		34		34		314
Exchange		95		74		—		21		298		298		—		—

Total	$	396	$	119	$	23	$	254	$	704	$	348	$	34	$	322


	September 30, 2015						December 31, 2014
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	214	$	—	$	214	$	202	$	—	$	202
Commodity contracts:
Over-the-counter		39		—		39		87		—		87
Exchange		84		—		84		493		—		493

Total derivatives, subject to a master netting or similar arrangement		337		—		337		782		—		782
Total derivatives, not subject to a master netting or similar arrangement		9		—		9		12		—		12

Total	$	346	$	—	$	346	$	794	$	—	$	794


			September 30, 2015								December 31, 2014
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	214	$	29	$	—	$	185	$	202	$	16	$	—	$	186
Commodity contracts:
Over-the-counter		39		16		—		23		87		34		1		52
Exchange		84		74		10		—		493		298		195		—

Total	$	337	$	119	$	10	$	208	$	782	$	348	$	196	$	238

Volumes

The following table presents the volume of Dominion’s derivative activity as of September 30, 2015. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price⁽¹⁾		57		14
Basis		267		605
Electricity (MWh):
Fixed price		13,869,299		3,399,889
FTRs		49,967,941		—
Capacity (MW)		12,200		—
Liquids (Gal)⁽²⁾		65,772,000		18,774,000
Interest rate	$	2,250,000,000	$	3,000,000,000

(1)	Includes options.

(2)	Includes NGLs and oil.

Ineffectiveness and AOCI

For the three and nine months ended September 30, 2015 and 2014, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at September 30, 2015:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After- Tax			Maximum Term
(millions)
Commodities:
Gas	$	(8	)	$	(7	)		25 months
Electricity		67			50			15 months
Other		5			4			18 months
Interest rate		(270	)		(9	)		387 months

Total	$	(206	)	$	38

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

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, 2015
ASSETS
Current Assets
Commodity	$	63	$	169	$	232
Interest rate		11		—		11

Total current derivative assets		74		169		243

Noncurrent Assets
Commodity		10		133		143
Interest rate		20		—		20

Total noncurrent derivative assets⁽¹⁾		30		133		163

Total derivative assets	$	104	$	302	$	406

LIABILITIES
Current Liabilities
Commodity	$	20	$	90	$	110
Interest rate		144		—		144

Total current derivative liabilities⁽²⁾		164		90		254

Noncurrent Liabilities
Commodity		6		16		22
Interest Rate		70		—		70

Total noncurrent derivative liabilities⁽³⁾		76		16		92

Total derivative liabilities	$	240	$	106	$	346

At December 31, 2014
ASSETS
Current Assets
Commodity	$	281	$	242	$	523
Interest rate		13		—		13

Total current derivative assets		294		242		536

Noncurrent Assets
Commodity		71		101		172
Interest rate		11		—		11

Total noncurrent derivative assets⁽¹⁾		82		101		183

Total derivative assets	$	376	$	343	$	719

LIABILITIES
Current Liabilities
Commodity	$	224	$	267	$	491
Interest rate		100		—		100

Total current derivative liabilities⁽²⁾		324		267		591

Noncurrent Liabilities
Commodity		55		46		101
Interest rate		102		—		102

Total noncurrent derivative liabilities⁽³⁾		157		46		203

Total derivative liabilities	$	481	$	313	$	794

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

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

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

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, 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	)

Three Months Ended September 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	66
Purchased gas					(3	)
Electric fuel and other energy-related purchases					(5	)

Total commodity	$	(74	)	$	58		$	—

Interest rate⁽³⁾		(20	)		(5	)		(7	)

Total	$	(94	)	$	53		$	(7	)

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	)

Nine Months Ended September 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	(175	)
Purchased gas					(7	)
Electric fuel and other energy-related purchases					8

Total commodity	$	(291	)	$	(174	)	$	(1	)

Interest rate⁽³⁾		(139	)		(11	)		(38	)

Total	$	(430	)	$	(185	)	$	(39	)

(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.


	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	2015			2014			2015			2014
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	2		$	35		$	20		$	(327	)
Purchased gas		(3	)		(39	)		(12	)		(33	)
Electric fuel and other energy-related purchases		(4	)		—			5			125
Interest rate⁽²⁾		(1	)		—			(1	)		—

Total	$	(6	)	$	(4	)	$	12		$	(235	)

(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, 2015						December 31, 2014
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	8	$	—	$	8	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		120		—		120		106		—		106

Total derivatives, subject to a master netting or similar arrangement		128		—		128		106		—		106
Total derivatives, not subject to a master netting or similar arrangement		22		—		22		7		—		7

Total	$	150	$	—	$	150	$	113	$	—	$	113


			September 30, 2015								December 31, 2014
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	8	$	7	$	—	$	1	$	—	$	—	$	—	$	—
Commodity contracts:
Over-the-counter		120		2		—		118		106		4		—		102

Total	$	128	$	9	$	—	$	119	$	106	$	4	$	—	$	102


	September 30, 2015						December 31, 2014
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	67	$	—	$	67	$	72	$	—	$	72
Commodity contracts:
Over-the-counter		2		—		2		8		—		8

Total derivatives, subject to a master netting or similar arrangement		69		—		69		80		—		80
Total derivatives, not subject to a master netting or similar arrangement		4		—		4		7		—		7

Total	$	73	$	—	$	73	$	87	$	—	$	87


			September 30, 2015								December 31, 2014
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	67	$	7	$	—	$	60	$	72	$	—	$	—	$	72
Commodity contracts:
Over-the-counter		2		2		—		—		8		4		—		4

Total	$	69	$	9	$	—	$	60	$	80	$	4	$	—	$	76

Volumes

The following table presents the volume of Virginia Power’s derivative activity as of September 30, 2015. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price⁽¹⁾		12		—
Basis		130		539
Electricity (MWh):
FTRs		49,069,990		—
Capacity (MW)		12,200		—
Interest rate	$	450,000,000	$	750,000,000

(1)	Includes options.

Ineffectiveness

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

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, 2015
ASSETS
Current Assets
Commodity	$	—	$	40	$	40

Total current derivative assets⁽¹⁾		—		40		40

Noncurrent Assets
Commodity		—		102		102
Interest rate		8		—		8

Total noncurrent derivative assets⁽²⁾		8		102		110

Total derivative assets	$	8	$	142	$	150

LIABILITIES
Current Liabilities
Commodity	$	—	$	6	$	6
Interest rate		39		—		39

Total current derivative liabilities⁽³⁾		39		6		45

Noncurrent Liabilities
Interest rate		28		—		28

Total noncurrent derivatives liabilities ⁽⁴⁾		28		—		28

Total derivative liabilities	$	67	$	6	$	73

At December 31, 2014
ASSETS
Current Assets
Commodity	$	—	$	51	$	51

Total current derivative assets⁽¹⁾		—		51		51

Noncurrent Assets
Commodity		—		62		62

Total noncurrent derivative assets⁽²⁾		—		62		62

Total derivative assets	$	—	$	113	$	113

LIABILITIES
Current Liabilities
Commodity	$	3	$	12	$	15
Interest rate		45		—		45

Total current derivative liabilities⁽³⁾		48		12		60

Noncurrent Liabilities
Interest rate		27		—		27

Total noncurrent derivative liabilities⁽⁴⁾		27		—		27

Total derivative liabilities	$	75	$	12	$	87

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

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

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

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

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, 2015
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	—

Total commodity	$	—		$	—		$	—

Interest rate⁽³⁾		(9	)		—			(69	)

Total	$	(9	)	$	—		$	(69	)

Three Months Ended September 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	(1	)

Total commodity	$	(1	)	$	(1	)	$	—

Interest rate⁽³⁾		—			—			(7	)

Total	$	(1	)	$	(1	)	$	(7	)

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	)

Nine Months Ended September 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity:
Electric fuel and other energy-related purchases				$	5

Total commodity	$	5		$	5		$	(1	)

Interest rate⁽³⁾		(5	)		—			(38	)

Total	$	—		$	5		$	(39	)

(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	2015			2014			2015		2014
(millions)
Derivative Type and Location of Gains (Losses)
Commodity⁽²⁾	$	(6	)	$	(3	)	$	6	$	108

Total	$	(6	)	$	(3	)	$	6	$	108

(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, 2015						December 31, 2014
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	9	$	—	$	9	$	2	$	—	$	2

Total derivatives, subject to a master netting or similar arrangement	$	9	$	—	$	9	$	2	$	—	$	2


			September 30, 2015								December 31, 2014
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	9	$	1	$	—	$	8	$	2	$	—	$	—	$	2

Total	$	9	$	1	$	—	$	8	$	2	$	—	$	—	$	2


	September 30, 2015						December 31, 2014
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Interest rate contracts:
Over-the-counter	$	17	$	—	$	17	$	9	$	—	$	9
Commodity contracts:
Over-the-counter		1		—		1		—		—		—

Total derivatives, subject to a master netting or similar arrangement	$	18	$	—	$	18	$	9	$	—	$	9


			September 30, 2015								December 31, 2014
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Interest rate contracts:
Over-the-counter	$	17	$	—	$	—	$	17	$	9	$	—	$	—	$	9
Commodity contracts:
Over-the-counter		1		1		—		—		—		—		—		—

Total	$	18	$	1	$	—	$	17	$	9	$	—	$	—	$	9

Volumes

The following table presents the volume of Dominion Gas’ derivative activity as of September 30, 2015. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price		3		—
Basis		3		—
NGLs (Gal)		64,302,000		16,758,000
Interest rate	$	—	$	250,000,000

Ineffectiveness and AOCI

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

The following table presents selected information related to losses on cash flow hedges included in AOCI in Dominion Gas’ Consolidated Balance Sheet at September 30, 2015:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
NGLs	$	5		$	4			18 months
Interest rate		(26	)		(1	)		351 months

Total	$	(21	)	$	3

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Dominion Gas’ commodity and interest rate derivatives and where they are presented in its Consolidated Balance Sheets:


	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At September 30, 2015
ASSETS
Current Assets
Commodity	$	6	$	1	$	7

Total current derivative assets⁽¹⁾		6		1		7

Noncurrent Assets
Commodity		2		—		2

Total noncurrent derivative assets⁽²⁾		2		—		2

Total derivative assets	$	8	$	1	$	9

LIABILITIES
Current Liabilities
Commodity	$	—	$	1	$	1

Total current derivative liabilities⁽³⁾		—		1		1

Noncurrent Liabilities
Interest rate		17		—		17

Total noncurrent derivative liabilities⁽⁴⁾		17		—		17

Total derivative liabilities	$	17	$	1	$	18

At December 31, 2014
ASSETS
Current Assets
Commodity	$	2	$	—	$	2

Total current derivative assets⁽¹⁾		2		—		2

Total derivative assets	$	2	$	—	$	2

LIABILITIES
Noncurrent Liabilities
Interest rate	$	9	$	—	$	9

Total noncurrent derivative liabilities⁽⁴⁾		9		—		9

Total derivative liabilities	$	9	$	—	$	9

(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, 2015
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	3

Total commodity	$	11		$	3

Interest rate⁽²⁾		(7	)		—

Total	$	4		$	3

Three Months Ended September 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	(1	)
Purchased gas					(5	)

Total commodity	$	3		$	(6	)

Interest rate⁽²⁾		(14	)		—

Total	$	(11	)	$	(6	)

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

Nine Months Ended September 30, 2014
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	(8	)
Purchased gas					(10	)

Total commodity	$	1		$	(18	)

Interest rate⁽²⁾		(56	)		—

Total	$	(55	)	$	(18	)

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

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


	Amount of Gain (Loss) Recognized in Income on Derivatives
	Three Months Ended September 30,				Nine Months Ended September 30,
Derivatives not designated as hedging instruments	2015		2014		2015		2014
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	1	$	—	$	5	$	—

Total	$	1	$	—	$	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 $96 million and $110 million at September 30, 2015 and December 31, 2014, respectively. Cost method investments held in Dominion’s rabbi trusts totaled $4 million and $6 million at September 30, 2015 and December 31, 2014, respectively.

Decommissioning Trust Securities

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


	Amortized Cost		Total Unrealized Gains⁽¹⁾		Total Unrealized Losses⁽¹⁾			Fair Value
(millions)
At September 30, 2015
Marketable equity securities:
U.S. large cap	$	1,260	$	1,106	$	—		$	2,366
REIT		59		—		—			59
Marketable debt securities:
Corporate bonds		454		15		(6	)		463
U.S. Treasury securities and agency debentures		602		13		(3	)		612
State and municipal		338		20		(1	)		357
Other		95		—		—			95
Cost method investments		72		—		—			72
Cash equivalents and other⁽²⁾		9		—		—			9

Total	$	2,889	$	1,154	$	(10	)⁽³⁾	$	4,033

At December 31, 2014
Marketable equity securities:
U.S. large cap	$	1,273	$	1,353	$	—		$	2,626
Marketable debt securities:
Corporate bonds		424		19		(2	)		441
U.S. Treasury securities and agency debentures		597		13		(4	)		606
State and municipal		332		23		—			355
Other		66		—		—			66
Cost method investments		86		—		—			86
Cash equivalents and other⁽²⁾		16		—		—			16

Total	$	2,794	$	1,408	$	(6	)⁽³⁾	$	4,196

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

(2)	Includes pending sales of securities of $5 million and $3 million at September 30, 2015 and December 31, 2014, respectively.

(3)	The fair value of securities in an unrealized loss position was $411 million and $379 million at September 30, 2015 and December 31, 2014, respectively.

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


	Amount
(millions)
Due in one year or less	$	209
Due after one year through five years		402
Due after five years through ten years		422
Due after ten years		494

Total	$	1,527

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,
	2015		2014		2015		2014
(millions)
Proceeds from sales	$	357	$	838	$	937	$	1,524
Realized gains⁽¹⁾		65		57		165		120
Realized losses⁽¹⁾		40		7		69		20

(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,
	2015			2014			2015			2014
(millions)
Total other-than-temporary impairment losses ⁽¹⁾	$	29		$	6		$	55		$	21
Losses recorded to nuclear decommissioning trust regulatory liability		(10	)		(1	)		(21	)		(5	)
Losses recognized in other comprehensive income (before taxes)		(3	)		(1	)		(7	)		(3	)

Net impairment losses recognized in earnings	$	16		$	4		$	27		$	13

(1)	Amounts include other-than-temporary impairment losses for debt securities of $3 million and $1 million for the three months ended September 31, 2015 and 2014, respectively, and $7 million and $3 million for the nine months ended September 31, 2015 and 2014, 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, 2015
Marketable equity securities:
U.S. large cap	$	558	$	478	$	—		$	1,036
REIT		59		—		—			59
Marketable debt securities:
Corporate bonds		249		7		(4	)		252
U.S. Treasury securities and agency debentures		224		2		(1	)		225
State and municipal		187		11		—			198
Other		30		—		—			30
Cost method investments		72		—		—			72
Cash equivalents and other⁽²⁾		3		—		—			3

Total	$	1,382	$	498	$	(5	)⁽³⁾	$	1,875

At December 31, 2014
Marketable equity securities:
U.S. large cap	$	563	$	594	$	—		$	1,157
Marketable debt securities:
Corporate bonds		242		9		(1	)		250
U.S. Treasury securities and agency debentures		197		3		(2	)		198
State and municipal		197		13		—			210
Other		23		—		—			23
Cost method investments		86		—		—			86
Cash equivalents and other⁽²⁾		6		—		—			6

Total	$	1,314	$	619	$	(3	)⁽³⁾	$	1,930

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

(2)	Includes pending sales of securities of $3 million at September 30, 2015 and $6 million at December 31, 2014.

(3)	The fair value of securities in an unrealized loss position was $209 million and $170 million at September 30, 2015 and December 31, 2014, respectively.

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


	Amount
(millions)
Due in one year or less	$	63
Due after one year through five years		181
Due after five years through ten years		236
Due after ten years		225

Total	$	705

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,
	2015		2014		2015		2014
(millions)
Proceeds from sales	$	198	$	116	$	407	$	415
Realized gains⁽¹⁾		45		22		82		51
Realized losses⁽¹⁾		18		2		33		8

(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, 2015 and 2014.

Equity Method Investments

Dominion and Dominion Gas

Iroquois

At September 30, 2015, Dominion Midstream used the equity method to account for its 25.93% noncontrolling partnership interest in Iroquois. At September 30, 2015, the carrying amount of Dominion Midstream’s investment of $216 million exceeded its share of underlying equity in net assets by approximately $122 million. The difference reflects equity method goodwill and is not being amortized.

Dominion Gas’ equity earnings on its 24.72% non-controlling partnership interest totaled $17 million for both the nine months ended September 30, 2015 and 2014. Dominion Gas received distributions from this investment of $26 million and $10 million for the nine months ended September 30, 2015 and 2014, respectively. At September 30, 2015 and December 31, 2014, the carrying amount of Dominion Gas’ investment of $98 million and $107 million, respectively, exceeded its share of underlying equity in net assets by approximately $8 million at both dates. The difference reflects equity method goodwill and is not being amortized.

Blue Racer

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

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

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

Note 11. Regulatory Assets and Liabilities

Regulatory assets and liabilities include the following:


	September 30, 2015		December 31, 2014
(millions)
Dominion
Regulatory assets:
Deferred cost of fuel used in electric generation⁽¹⁾	$	107	$	79
Deferred rate adjustment clause costs⁽²⁾		119		124
Deferred nuclear refueling outage costs⁽³⁾		59		44


Unrecovered gas costs⁽⁴⁾		12		36
Other		59		64

Regulatory assets-current⁽⁵⁾		356		347

Unrecognized pension and other postretirement benefit costs⁽⁶⁾		1,000		1,050
Deferred rate adjustment clause costs⁽²⁾		227		250
Income taxes recoverable through future rates⁽⁷⁾		121		133
Derivatives⁽⁸⁾		125		101
Other		120		108

Regulatory assets-non-current		1,593		1,642

Total regulatory assets	$	1,949	$	1,989

Regulatory liabilities:
PIPP⁽⁹⁾	$	52	$	71
Other		63		99

Regulatory liabilities-current⁽¹⁰⁾		115		170

Provision for future cost of removal and AROs⁽¹¹⁾		1,136		1,072
Nuclear decommissioning trust⁽¹²⁾		745		815
Deferred cost of fuel used in electric generation⁽¹⁾		73		6
Other		219		98

Regulatory liabilities-non-current		2,173		1,991

Total regulatory liabilities	$	2,288	$	2,161

Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation⁽¹⁾	$	107	$	79
Deferred nuclear refueling outage costs⁽³⁾		59		44
Deferred rate adjustment clause costs⁽²⁾		106		117
Other		56		58

Regulatory assets-current		328		298

Deferred rate adjustment clause costs⁽²⁾		148		179
Income taxes recoverable through future rates⁽⁷⁾		93		100
Derivatives⁽⁸⁾		125		101
Other		56		59

Regulatory assets-non-current		422		439

Total regulatory assets	$	750	$	737

Regulatory liabilities:
Other	$	44	$	90

Regulatory liabilities-current⁽¹⁰⁾		44		90

Provision for future cost of removal⁽¹¹⁾		886		852
Nuclear decommissioning trust⁽¹²⁾		745		815
Deferred cost of fuel used in electric generation⁽¹⁾		73		6
Other		118		10

Regulatory liabilities-non-current		1,822		1,683

Total regulatory liabilities	$	1,866	$	1,773

Dominion Gas
Regulatory assets:
Deferred rate adjustment clause costs⁽²⁾	$	13	$	7
Unrecovered gas costs⁽⁴⁾		10		29
Other		1		2

Regulatory assets-current⁽⁵⁾		24		38


Unrecognized pension and other postretirement benefit costs⁽⁶⁾		231		242
Deferred rate adjustment clause costs⁽²⁾		78		71
Income taxes recoverable through future rates⁽⁷⁾		19		24
Other		59		42

Regulatory assets-non-current⁽¹³⁾		387		379

Total regulatory assets	$	411	$	417

Regulatory liabilities:
PIPP⁽⁹⁾	$	52	$	71
Other		10		4

Regulatory liabilities-current⁽¹⁰⁾		62		75

Provision for future cost of removal and AROs⁽¹¹⁾		171		172
Other		36		20

Regulatory liabilities-non-current⁽¹⁴⁾		207		192

Total regulatory liabilities	$	269	$	267

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

(2)

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

(3)	Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months.

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

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

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

(7)

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

(8)

For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or passed on to customers based on the ultimate settlement amount of the derivative.

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

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

(11)	Rates charged to customers by the Companies’ regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.

(12)

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

(13)	Noncurrent regulatory 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, 2015, approximately $120 million of Dominion’s, $91 million of Virginia Power’s and $27 million of Dominion Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. These expenditures are expected to be recovered within the next two years.

Note 12. Regulatory Matters

Regulatory Matters Involving Potential Loss Contingencies

As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For matters for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed

sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters for which the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on the Companies’ financial position, liquidity or results of operations.

FERC - Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Dominion’s merchant generators sell electricity in the PJM, MISO, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Tennessee, Georgia and California under Dominion’s market-based sales tariffs authorized by FERC. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in the wholesale market. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.

Rates

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

In March 2010, ODEC and NCEMC filed a complaint with FERC against Virginia Power claiming that approximately $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. In February 2012, Virginia Power submitted to FERC a settlement agreement to resolve all issues set for hearing. The settlement was accepted by FERC in May 2012 and provides for payment by Virginia Power to the transmission customer parties collectively of $250,000 per year for ten years and resolves all matters other than allocation of the incremental cost of certain underground transmission facilities.

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

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

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

Other Regulatory Matters

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015.

Virginia Regulation

Biennial Review

In connection with its current biennial review of Virginia Power’s base rates, terms and conditions, the Virginia Commission is reviewing Virginia Power’s earnings on its rates for generation and distribution services for the combined 2013 and 2014 test periods, and determining whether credits are due to customers in the event Virginia Power’s earnings exceeded the authorized ROE band of 9.3% to 10.7%. In September 2015, the Virginia Commission conducted an evidentiary hearing related to the biennial review. In its testimony, the Virginia Commission staff proposed making several regulatory adjustments to Virginia Power’s earnings. If the Virginia Commission were to accept all of these proposed adjustments, Virginia Power would have earned an ROE of 11.34% during the 2013 and 2014 test years, resulting in a total credit to customers of approximately $65 million. Virginia Power believes that the adjustments proposed by the Virginia Commission staff were improper and inconsistent with prior regulatory precedent. Virginia Power demonstrated that its costs, revenues and investments for the combined test periods resulted in an earned return of 10.13%, which is within the allowed range. Due to the uncertainty surrounding the Virginia Commission’s final ruling expected to be issued by the end of November 2015, Virginia Power has not recognized a liability related to the staff’s recommendation as of September 30, 2015.

Virginia Fuel Expenses

In August 2015, the Virginia Commission approved Virginia Power’s annual fuel factor filing to recover an estimated $1.6 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2015. Virginia Power’s new approved fuel rate, in effect on an interim basis since April 1, 2015, represents a fuel revenue decrease of approximately $512 million when applied to projected kilowatt-hour sales for the period April 1, 2015 to June 30, 2016.

Remington Solar Facility

In January 2015, Virginia Power applied for a CPCN to construct and operate a 20 MW utility-scale solar facility near its existing Remington Power Station in Fauquier County, Virginia. Virginia Power also applied for approval of Rider US-1 to recover the costs of the facility. In October 2015, the Virginia Commission denied approval of the CPCN and Rider US-1 based on the evidence in the record but stated that an application could be re-filed to address the concerns cited by the Virginia Commission. Virginia Power is reviewing the order and assessing its options.

Rate Adjustment Clauses

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

•

The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In August 2015, Virginia Power proposed a total revenue requirement of approximately $50 million for the rate year beginning May 1, 2016. Virginia Power further proposed two new energy efficiency programs for Virginia Commission approval with a requested five-year cost cap of approximately $51 million for those programs, and to extend an existing peak-shaving program for an additional five years under current funding. This case is pending.

•

The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In October 2015, Virginia Power proposed an approximately $156 million total revenue requirement for the rate year beginning September 1, 2016, which represents an approximately $45 million increase versus the previous year. This case is pending.

North Anna

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna. If Virginia Power decides to build a new unit, it must first receive a COL from the NRC, approval of the Virginia Commission and certain environmental permits and other approvals. The COL is expected in 2017. Virginia Power has not yet committed to building a new nuclear unit at North Anna.

The motions and petitions filed by BREDL prior to April 2015 have been dismissed, and under a previous ruling of the NRC, the contested portion of the COL proceeding remains terminated. The NRC is required to conduct a hearing in all COL proceedings, and if a new contention is not admitted, the mandatory NRC hearing will be uncontested.

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

In August 2015, BREDL filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking review of the NRC’s June 2015 decision. Along with the petition for judicial review, BREDL also filed a motion to hold this judicial review in abeyance pending the outcome of the ongoing judicial review of the NRC’s rule pertaining to the continued onsite storage of spent nuclear fuel in litigation pending before the same court. Similar petitions were filed seeking judicial review of the NRC’s decision as it applies to other COL and license renewal proceedings. Virginia Power has filed a motion with the court to intervene in the proceeding. This case is pending.

North Carolina Regulation

In August 2015, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed an approximately $11 million decrease to the fuel component of its electric rates for the rate year beginning January 1, 2016. This decrease includes the North Carolina Commission’s previous approval to defer recovering 50% of Virginia Power’s estimated $17 million jurisdictional deferred fuel balance to the 2016 fuel year, without interest. This case is pending.

FERC - Gas

In August 2015, FERC approved DTI’s Clarington Project, which is expected to cost approximately $80 million. The project is expected to provide 250,000 Dths per day of firm transportation service from central West Virginia to Clarington, Ohio. Construction is expected to commence in the fourth quarter of 2015 and to be placed into service in the fourth quarter of 2016.

In October 2015, Cove Point received authorization to construct the approximately $30 million St. Charles Transportation Project and the approximately $40 million Keys Energy Project. Construction on each project is expected to commence in the fourth quarter of 2015. The St. Charles Transportation project is anticipated to be placed into service in June 2016. The Keys Energy Project is anticipated to be placed into service in March 2017.

Note 13. Asset Retirement Obligations

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

The Companies have also identified, but not recognized, AROs related to retirement of Dominion’s LNG facility, Dominion Gas’ storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in Dominion’s and Virginia Power’s generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs for Dominion and Virginia Power during 2014 and 2015 are presented below. There were no significant changes to Dominion Gas’ AROs.


	Amount
(millions)
Dominion
AROs at December 31, 2013⁽¹⁾	$	1,578
Obligations incurred during the period		40
Obligations settled during the period		(82	)
Revisions in estimated cash flows⁽²⁾		102
Accretion		81
Other		(5	)

AROs at December 31, 2014⁽¹⁾	$	1,714

Obligations incurred during the period⁽³⁾		307
Obligations settled during the period		(72	)
Revisions in estimated cash flows⁽³⁾		35
Accretion		69
Other		(1	)

AROs at September 30, 2015⁽¹⁾	$	2,052

Virginia Power
AROs at December 31, 2013	$	689
Obligations incurred during the period		28
Obligations settled during the period		(1	)
Revisions in estimated cash flows⁽²⁾		108
Accretion		37
Other		(6	)

AROs at December 31, 2014⁽⁴⁾	$	855

Obligations incurred during the period⁽³⁾		288
Obligations settled during the period		(22	)
Revisions in estimated cash flows⁽³⁾		32
Accretion		36

AROs at September 30, 2015⁽⁴⁾	$	1,189

(1)	Includes $94 million, $81 million and $228 million reported in other current liabilities at December 31, 2013, December 31, 2014 and September 30, 2015, respectively.

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

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

(4)	Includes $7 million and $159 million reported in other current liabilities at December 31, 2014 and September 30, 2015, respectively.

Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At September 30, 2015 and December 31, 2014, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $4.0 billion and $4.2 billion, respectively. At September 30, 2015 and December 31, 2014, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.9 billion.

Note 14. Variable Interest Entities

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

Dominion and Dominion Gas

Iroquois

Dominion Midstream and Dominion Gas own a 25.93% and 24.72% noncontrolling partnership interest in Iroquois, respectively. See Note 3 for further details regarding the nature of this entity. Dominion concluded that Iroquois is a VIE because a non-affiliated Iroquois equity holder has the ability during a limited period of time to transfer its ownership interests to another Iroquois equity holder or its affiliate. At September 30, 2015, Dominion concluded that neither Dominion Midstream

nor Dominion Gas is the primary beneficiary of Iroquois as they do not have the power to direct the activities of Iroquois that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. If Iroquois determines capital contributions are required, Dominion Midstream and Dominion Gas each would be obligated to provide the portion of capital contributions based on its ownership percentage. Dominion Midstream’s and Dominion Gas’ maximum exposure to loss is limited to its current and future investment.

Virginia Power

Virginia Power has long-term power and capacity contracts with five non-utility generators with an aggregate summer generation capacity of approximately 870 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $478 million as of September 30, 2015. Virginia Power paid $52 million and $55 million for electric capacity and $17 million and $28 million for electric energy to these entities in the three months ended September 30, 2015 and 2014, respectively. Virginia Power paid $160 million and $166 million for electric capacity and $77 million and $115 million for electric energy to these entities in the nine months ended September 30, 2015 and 2014, respectively.

Virginia Power and Dominion Gas

Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of approximately $73 million and $27 million for the three months ended September 30, 2015, $82 million and $27 million for the three months ended September 30, 2014, $239 million and $85 million for the nine months ended September 30, 2015, and $246 million and $78 million for the nine months ended September 30, 2014, respectively. Virginia Power and Dominion Gas determined that each is not the most closely associated entity with DRS and therefore neither is the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power and Dominion Gas. Virginia Power and Dominion Gas have no obligation to absorb more than their allocated shares of DRS costs.

Note 15. Significant Financing Transactions

Credit Facilities and Short-term Debt

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

Dominion

At September 30, 2015, Dominion’s commercial paper and letters of credit outstanding, as well as its capacity available under credit facilities, were as follows:


	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility⁽¹⁾	$	4,000	$	2,555	$	—	$	1,445
Joint revolving credit facility⁽¹⁾		500		—		57		443

Total	$	4,500	$	2,555	$	57	$	1,888

(1)	These credit facilities mature in April 2019, and can be used 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.

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, 2015, 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⁾

4,000

1,362

—

Joint revolving credit facility⁽¹⁾

500

—

Total

4,500

1,362

—

(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, 2015, the sub-limit for Virginia Power was an aggregate $1.75 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. These credit facilities mature in April 2019, and 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 with a maturity date of April 2019. As of September 30, 2015, this facility supports approximately $119 million of certain variable rate tax-exempt financings of Virginia Power.

Dominion Gas

Dominion Gas’ short-term financing is supported by its access as co-borrower to the two joint revolving credit facilities. In December 2014, Dominion Gas entered into a commercial paper program pursuant to which it began accessing the commercial paper markets in January 2015.

At September 30, 2015, 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

382

—

Joint revolving credit facility⁽¹⁾

500

—

Total

1,500

382

—

(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. At September 30, 2015, the sub-limit for Dominion Gas was an aggregate $500 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. These credit facilities mature in April 2019, and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

Long-term Debt

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

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

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

In August 2015, Virginia Power remarketed five series of tax-exempt bonds, with an aggregate outstanding principal of $412 million to new investors. Two of the bonds will bear interest at a coupon rate of 1.75% for the first four years after which they will bear interest at a market rate to be determined at that time. Three of the bonds will bear interest at a coupon rate of 2.15% for the first five years after which they will bear interest at a market rate to be determined at that time. Previously, interest on all of the remarketed bonds was variable and reset monthly. This remarketing was accounted for as a debt extinguishment with the previous investors.

In September 2015, Dominion issued $650 million of 3.90% senior notes that mature in 2025.

Issuance of Common Stock

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

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

Note 16. Commitments and Contingencies

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

Environmental Matters

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

Air

The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies’ facilities are subject to the CAA’s permitting and other requirements.

In December 2011, the EPA issued MATS for coal- and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an

exemption from emission limits, and allows compliance with operational work practice standards. Compliance was required by April 16, 2015, with certain limited exceptions. However, in June 2014, the VDEQ granted a one-year MATS compliance extension for two coal-fired units at Yorktown to defer planned retirements and allow for continued operation of the units to address reliability concerns while necessary electric transmission upgrades are being completed. These coal units will need to continue operating until at least April 2017 due to delays in transmission upgrades needed to maintain electric reliability, which based on assumptions about the timing for required agency actions and construction schedules are expected to be completed by no earlier than the second quarter of 2017. Therefore, in October 2015 Virginia Power submitted a request to the EPA for an additional one year compliance extension under an EPA Administrative Order.

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

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

Following numerous petitions by industry participants for review and a successful motion for stay, in October 2014, the U.S. Court of Appeals for the D.C. Circuit ordered that the EPA’s motion to lift the stay of CSAPR be granted. Further, the Court granted the EPA’s request to shift the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets (which would have gone into effect in 2012 and 2013) will apply in 2015 and 2016, and Phase 2 emissions budgets will apply in 2017 and beyond. CSAPR replaced CAIR beginning in January 2015. The cost to comply is not expected to be material to the Consolidated Financial Statements. Future outcomes of any additional litigation and/or any action to issue a revised rule could affect the assessment regarding cost of compliance.

In October 2015, the EPA issued a final rule tightening the ozone standard from 75 ppb to 70 ppb. 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.

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

In August 2012, the EPA issued the first NSPS impacting the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of 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 to regulate methane and VOC emissions from transmission and storage, gathering and boosting, production and processing facilities. All projects which commence construction after September 2015 will be required to comply with this regulation. Dominion is evaluating the proposed regulation and cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.

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. Dominion is evaluating the proposed program and cannot currently estimate the potential impacts on results of operations, financial condition and/or cash flows related to this matter.

Water

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

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power are currently evaluating the need or potential for 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. Dominion has seven 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 U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.

From time to time, Dominion, Virginia Power, or Dominion Gas may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion, Virginia Power, or Dominion Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. Except as noted below, the Companies do not believe this will have a material effect on results of operations, financial condition and/or cash flows.

In September 2011, the EPA issued a UAO to Virginia Power and 22 other parties, ordering specific remedial action of certain areas at the Ward Transformer Superfund site located in Raleigh, North Carolina. Virginia Power does not believe it is a liable party under CERCLA based on its alleged connection to the site. In November 2011, Virginia Power and a number of other parties notified the EPA that they are declining to undertake the work set forth in the UAO.

The EPA may seek to enforce a UAO in court pursuant to its enforcement authority under CERCLA, and may seek recovery of its costs in undertaking removal or remedial action. If the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party’s failure to comply with the UAO. Virginia Power is currently unable to make an estimate of the potential financial statement impacts related to the Ward Transformer matter.

Dominion has determined that it is associated with 17 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion Gas. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which the Companies are associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion is conducting a state-approved post-closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.

See below for discussion on ash pond closure costs.

Climate Change Legislation and Regulation

In October 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the D.C. Circuit Court’s June 2012 decision upholding the EPA’s regulation of GHG emissions from stationary sources under the CAA’s permitting programs. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the EPA’s ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. In July 2014, the EPA issued a memorandum specifying that it will no longer apply or enforce federal regulations or EPA-approved PSD state implementation plan provisions that require new and modified stationary sources to obtain a PSD permit when GHGs are the only pollutant that would be emitted at levels that exceed the permitting thresholds. In August 2015, the EPA published a final rule rescinding the requirement for all new and modified major sources to obtain permits based solely on their GHG emissions. In addition, the EPA stated that it will continue to use the existing thresholds to apply to sources that are otherwise subject to PSD for conventional pollutants until it completes a new rulemaking either justifying and upholding those thresholds or setting new ones. Some states have issued interim guidance that follows the EPA guidance. Due to uncertainty regarding what additional actions states may take to amend their existing regulations and what action the EPA ultimately takes to address the court ruling under a new rulemaking, the Companies cannot predict the impact to their financial statements at this time.

In July 2011, the EPA signed a final rule deferring the need for PSD and Title V permitting for CO₂ emissions for biomass projects. This rule temporarily deferred for a period of up to three years the consideration of CO₂ emissions from biomass projects when determining whether a stationary source meets the PSD and Title V applicability thresholds, including those for the application of BACT. The deferral policy expired in July 2014. In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however, a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomass during the CO₂ deferral period. It is unclear how the court’s decision or the EPA’s final policy regarding the treatment of specific feedstock will affect biomass sources that were permitted during the deferral period; however, the expenditures to comply with any new requirements could be material to Dominion’s and Virginia Power’s financial statements.

Other Legal Matters

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

Appalachian Gateway

Following the completion of the Appalachian Gateway Project in 2012, DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DTI filed a complaint in U.S. District Court 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 U.S. 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. This case is pending. DTI has accrued a liability of approximately $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.

Ash Pond Closure Costs

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

In April 2015, the EPA’s final rule regulating the management of CCRs stored in impoundments (ash ponds) and landfills was published in the Federal Register. The final rule regulates CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store CCRs. Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. The enactment of the final rule in April 2015 created a legal obligation for Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary. In the second quarter of 2015, Virginia Power recorded a $325 million ARO related to future ash pond and landfill closure costs. Recognition of the ARO also resulted in a $45 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $159 million increase in property, plant, and equipment associated with asset retirement costs, and a $121 million reduction in other noncurrent liabilities related to reversal of the contingent liability described above since the ARO obligation created by the final CCR rule represents similar activities. Dominion is in the process of obtaining the necessary permits to complete the work. The actual asset retirement costs related to the CCR rule may vary substantially from the estimates used to record the increased obligation in the second quarter, due to compliance requirements that may be imposed by the various state regulators.

Nuclear Matters

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

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

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

Guarantees, Surety Bonds and Letters of Credit

Dominion

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

Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion’s consolidated subsidiaries, that liability is included in the Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.

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


	Stated Limit		Value⁽¹⁾
(millions)
Subsidiary debt⁽²⁾	$	27	$	27
Commodity transactions⁽³⁾		2,682		1,075
Nuclear obligations⁽⁴⁾		197		75
Cove Point⁽⁵⁾		1,910		—
Solar⁽⁶⁾		1,401		848
Other⁽⁷⁾		514		31

Total	$	6,731	$	2,056

(1)

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

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

(3)

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

(4)

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

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

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

(7)

Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations and construction projects. Also includes guarantees related to certain DEI subsidiaries’ obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of September 30, 2015, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $55 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, 2015, Dominion had purchased $91 million of surety bonds, including $31 million at Virginia Power and $23 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $57 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

Note 17. Credit Risk

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

At September 30, 2015, Dominion’s credit exposure related to energy marketing and price risk management activities totaled $195 million. Of this amount, investment grade counterparties, including those internally rated, represented 64%. No single counterparty, whether investment grade or non-investment grade, exceeded $35 million of exposure.

Credit-Related Contingent Provisions

The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of September 30, 2015 and December 31, 2014, Dominion would have been required to post an additional $14 million and $20 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion had not posted any collateral at September 30, 2015 related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. Dominion had posted approximately $1 million in collateral at December 31, 2014 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, 2015 and December 31, 2014 was $32 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, 2015 and December 31, 2014. See Note 9 for further information about derivative instruments.

Dominion Gas

In the third quarter of 2015, DTI provided service to 244 customers with approximately 95% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 45% of total storage and transportation revenue and the thirty largest provided approximately 72% of total storage and transportation revenue. Approximately 98% of the transmission capacity under contract on DTI’s pipeline is subscribed with long-term contracts (two years or greater). The remaining 2% is contracted on a year-to-year basis. Less than 1% of firm transportation capacity is currently unsubscribed. More than 99% of DTI’s storage capacity is under long-term contracts with less than 1% currently unsubscribed.

East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates approved by the Ohio Commission. Approximately 99% of East Ohio revenues are derived from its jurisdictional gas services. East Ohio’s bad debt risk is mitigated by the regulatory framework established by the Ohio Commission.

Note 18. Related Party Transactions

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

Virginia Power

Transactions with Affiliates

Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps, to manage commodity price risks associated with purchases of natural gas. As of September 30, 2015, Virginia Power’s derivative assets and liabilities with affiliates were $22 million and $4 million, respectively. As of December 31, 2014, Virginia Power’s derivative assets and liabilities with affiliates were not material. See Notes 7 and 9 for more information.

Virginia Power participates in certain Dominion benefit plans described in Note 19. In Virginia Power’s Consolidated Balance Sheets at September 30, 2015 and December 31, 2014, amounts due to Dominion associated with these benefit plans included in other deferred credits and other liabilities were $292 million and $219 million, respectively, and amounts due from Dominion at September 30, 2015 and December 31, 2014 included in other deferred charges and other assets were $66 million and $37 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,
	2015		2014		2015		2014
(millions)
Commodity purchases from affiliates	$	123	$	120	$	469	$	435
Services provided by affiliates⁽¹⁾		96		106		313		320
Services provided to affiliates		5		5		15		16

(1)	Includes capitalized expenditures.

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

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

Dominion Gas

Transactions with Related Parties

Dominion Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Gas provides transportation and storage services to affiliates. Dominion Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of September 30, 2015 and December 31, 2014, all of Dominion Gas’ commodity derivatives were with affiliates. See Notes 7 and 9 for more information. See Note 10 for information regarding sales of assets to an affiliate.

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
(millions)
Purchases of natural gas and transportation and storage services from affiliates	$	3	$	6	$	7	$	14
Sales of natural gas and transportation and storage services to affiliates		17		19		52		65
Services provided by related parties⁽¹⁾		30		27		99		78
Services provided to related parties ⁽²⁾		30		16		75		38

(1)	Includes capitalized expenditures.

(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, 2015		December 31, 2014
(millions)
Other receivables ⁽¹⁾	$	9	$	17
Customer receivables from related parties		4		5
Imbalances receivable from affiliates⁽²⁾		1		3
Affiliated notes receivable⁽³⁾		13		9

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

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

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

Dominion Gas’ borrowings under the IRCA with Dominion totaled $198 million as of September 30, 2015 and $384 million as of December 31, 2014. Interest charges related to Dominion Gas’ total borrowings from Dominion were immaterial for the three and nine months ended September 30, 2015 and 2014.

Note 19. Employee Benefit Plans

Dominion

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


	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
(millions)
Three Months Ended September 30,
Service cost	$	32		$	29		$	10		$	7
Interest cost		71			73			17			17
Expected return on plan assets		(132	)		(126	)		(29	)		(28	)
Amortization of prior service credit		—			—			(7	)		(7	)
Amortization of net actuarial loss		40			28			1			1
Settlements and curtailments		—			1			—			—

Net periodic benefit cost (credit)	$	11		$	5		$	(8	)	$	(10	)

Nine Months Ended September 30,
Service cost	$	95		$	86		$	30		$	23
Interest cost		215			218			50			50
Expected return on plan assets		(398	)		(376	)		(88	)		(83	)
Amortization of prior service cost (credit)		1			2			(20	)		(21	)
Amortization of net actuarial loss		120			84			4			2
Settlements and curtailments		—			1			—			—

Net periodic benefit cost (credit)	$	33		$	15		$	(24	)	$	(29	)

Employer Contributions

During the nine months ended September 30, 2015, Dominion made no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs during the remainder of 2015.

Dominion Gas

Dominion Gas participates in certain Dominion benefit plans as described in Note 21 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. At September 30, 2015 and December 31, 2014, Dominion Gas’ amounts due from Dominion associated with the Dominion Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $642 million and $614 million, respectively. At September 30, 2015 and December 31, 2014, Dominion Gas’ amounts due to Dominion associated with the Dominion Retiree Health and Welfare Plan and reflected in other deferred credits and other liabilities in the Consolidated Balance Sheets were $4 million and $7 million, respectively.

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


	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
(millions)
Three Months Ended September 30,
Service cost	$	4		$	3		$	2		$	1
Interest cost		7			7			3			4
Expected return on plan assets		(31	)		(29	)		(6	)		(6	)
Amortization of prior service cost		—			1			—			—
Amortization of net actuarial loss		5			5			1			—

Net periodic benefit credit	$	(15	)	$	(13	)	$	—		$	(1	)

Nine Months Ended September 30,
Service cost	$	11		$	9		$	5		$	4
Interest cost		21			21			10			10
Expected return on plan assets		(94	)		(86	)		(18	)		(17	)
Amortization of prior service cost (credit)		—			1			—			(1	)
Amortization of net actuarial loss		15			14			2			—

Net periodic benefit credit	$	(47	)	$	(41	)	$	(1	)	$	(4	)

Employer Contributions

During the nine months ended September 30, 2015, Dominion Gas made no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion Gas expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs, for both employees represented by collective bargaining units and employees not represented by collective bargaining units, during the remainder of 2015.

Note 20. Operating Segments

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


Primary Operating Segment	Description of Operations	Dominion	Virginia Power	Dominion Gas
DVP	Regulated electric distribution	X	X
	Regulated electric transmission	X	X
Dominion Generation	Regulated electric fleet	X	X
	Merchant electric fleet	X
	Nonregulated retail energy marketing	X
Dominion Energy	Gas transmission and storage⁽¹⁾	X		X
	Gas distribution and storage	X		X
	Gas gathering and processing	X		X
	LNG import and storage	X

(1)	Includes remaining producer services activities for Dominion.

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

Dominion

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

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

In the second quarter of 2013, Dominion commenced a repositioning of its producer services business, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates. The repositioning was completed in the first quarter of 2014 and resulted in the termination of natural gas trading and certain energy marketing activities. As a result, the earnings impact from natural gas trading and certain energy marketing activities has been included in the Corporate and Other Segment of Dominion for 2014.

In the 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. In the nine months ended September 30, 2014, Dominion reported an after-tax net expense of $446 million for specific items in the Corporate and Other segment, with $435 million of these net expenses attributable to its operating segments.

The net expense for specific items in 2015 primarily related to the impact of the following items, 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 net expense for specific items in 2014 primarily related to the impact of the following items:

•

$330 million ($219 million after-tax) of charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, attributable to Dominion Generation;

•

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

•

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

•

A $38 million ($23 million after-tax) one-time charge related to the implementation of a depreciation study retroactive to prior periods as ordered by the Virginia Commission, primarily attributable to Dominion Generation; partially offset by

•

A $53 million ($33 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.

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


	DVP		Dominion Generation		Dominion Energy		Corporate and Other			Adjustments/ Eliminations			Consolidated Total
(millions)
Three Months Ended September 30, 2015
Total revenue from external customers	$	539	$	1,920	$	335	$	—		$	177		$	2,971
Intersegment revenue		4		12		195		128			(339	)		—

Total operating revenue		543		1,932		530		128			(162	)		2,971
Net income (loss) attributable to Dominion		125		391		152		(75	)		—			593

Three Months Ended September 30, 2014
Total revenue from external customers	$	480	$	1,985	$	380	$	4		$	201		$	3,050
Intersegment revenue		4		11		223		140			(378	)		—

Total operating revenue		484		1,996		603		144			(177	)		3,050
Net income (loss) attributable to Dominion		119		326		144		(60	)		—			529

Nine Months Ended September 30, 2015
Total revenue from external customers	$	1,603	$	5,742	$	1,107	$	(9	)	$	684		$	9,127
Intersegment revenue		14		50		718		414			(1,196	)		—

Total operating revenue		1,617		5,792		1,825		405			(512	)		9,127
Net income (loss) attributable to Dominion		382		923		488		(251	)		—			1,542

Nine Months Ended September 30, 2014
Total revenue from external customers	$	1,425	$	5,936	$	1,171	$	10		$	951		$	9,493
Intersegment revenue		13		48		964		422			(1,447	)		—

Total operating revenue		1,438		5,984		2,135		432			(496	)		9,493
Net income (loss) attributable to Dominion		366		794		482		(575	)		—			1,067

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

Virginia Power

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

In the 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. In the nine months ended September 30, 2014, Virginia Power reported an after-tax net expense of $235 million for specific items in the Corporate and Other segment, with $239 million of these net expenses attributable to its operating segments.

The net expense for specific items in 2015 primarily related to the impact of the following items, 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 net expense for specific items in 2014 primarily related to the impact of the following items:

•

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, 2015
Operating revenue	$	541	$	1,523	$	(6	)	$	2,058
Net income (loss)		125		273		(13	)		385

Three Months Ended September 30, 2014
Operating revenue	$	483	$	1,570	$	—		$	2,053
Net income (loss)		120		248		(54	)		314

Nine Months Ended September 30, 2015
Operating revenue	$	1,610	$	4,419	$	(21	)	$	6,008
Net income (loss)		382		618		(100	)		900

Nine Months Ended September 30, 2014
Operating revenue	$	1,433	$	4,332	$	—		$	5,765
Net income (loss)		371		570		(234	)		707

Dominion Gas

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

In the nine months ended September 30, 2015 and 2014, Dominion Gas reported no amounts for specific items in the Corporate and Other segment.

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


	Dominion Energy		Corporate and Other			Consolidated Total
(millions)
Three Months Ended September 30, 2015
Operating revenue	$	365	$	—		$	365
Net income (loss)		113		(2	)		111

Three Months Ended September 30, 2014
Operating revenue	$	391	$	—		$	391
Net income (loss)		108		(1	)		107

Nine Months Ended September 30, 2015
Operating revenue	$	1,291	$	—		$	1,291
Net income (loss)		364		(7	)		357

Nine Months Ended September 30, 2014
Operating revenue	$	1,388	$	—		$	1,388
Net income (loss)		370		(6	)		364

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Contents of MD&A

MD&A consists of the following information:

•

Forward-Looking Statements

•

Accounting Matters - Dominion

•

Dominion

•

Results of Operations

•

Segment Results of Operations

•

Virginia Power

•

Results of Operations

•

Dominion Gas

•

Results of Operations

•

Liquidity and Capital Resources - Dominion

•

Future Issues and Other Matters - Dominion

Forward-Looking Statements

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

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

Counterparty credit and performance risk;

•

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

•

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

•

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

•

Fluctuations in interest rates;

•

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

•

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

•

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

•

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

•

Impacts of acquisitions, divestitures, transfers of assets to joint ventures or Dominion Midstream, and retirements of assets based on asset portfolio reviews;

•

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

•

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

•

Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;

•

Political and economic conditions, including inflation and deflation;

•

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

•

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

•

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

•

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

•

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

•

Changes in operating, maintenance and construction costs;

•

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

•

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

•

Adverse outcomes in litigation matters or regulatory proceedings; and

•

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

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.

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

Accounting Matters

Critical Accounting Policies and Estimates

As of September 30, 2015 there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. The policies disclosed included the accounting for regulated operations, AROs, income taxes, derivative contracts and other instruments at fair value, goodwill and long-lived asset impairment testing and employee benefit plans.

Dominion

Results of Operations

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


	2015		2014		$ Change
(millions, except EPS)
Third Quarter
Net income attributable to Dominion	$	593	$	529	$	64
Diluted EPS		1.00		0.90		0.10

Year-To-Date
Net income attributable to Dominion	$	1,542	$	1,067	$	475
Diluted EPS		2.60		1.83		0.77

Overview

Third Quarter 2015 vs. 2014

Net income attributable to Dominion increased 12%, primarily due to a gain from an agreement to convey shale development rights underneath a natural gas storage field and the absence of charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities.

Year-To-Date 2015 vs. 2014

Net income attributable to Dominion increased 45%, primarily due to the absence of charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, the absence of losses related to the repositioning of Dominion’s producer services business, which was completed in the first quarter of 2014, and gains from agreements to convey shale development rights underneath natural gas storage fields.

Analysis of Consolidated Operations

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


	Third Quarter							Year-To-Date
	2015		2014		$ Change			2015		2014		$ Change
(millions)
Operating revenue	$	2,971	$	3,050	$	(79	)	$	9,127	$	9,493	$	(366	)
Electric fuel and other energy-related purchases		636		743		(107	)		2,180		2,710		(530	)
Purchased electric capacity		75		86		(11	)		259		261		(2	)
Purchased gas		85		209		(124	)		446		1,073		(627	)

Net revenue		2,175		2,012		163			6,242		5,449		793

Other operations and maintenance		564		614		(50	)		1,875		1,972		(97	)
Depreciation, depletion and amortization		355		354		1			1,037		970		67
Other taxes		133		123		10			432		424		8
Other income		11		69		(58	)		127		166		(39	)
Interest and related charges		230		231		(1	)		674		695		(21	)
Income tax expense		305		228		77			794		477		317

An analysis of Dominion’s results of operations follows:

Third Quarter 2015 vs. 2014

Net revenue increased 8%, primarily reflecting:

•

A $111 million increase from electric utility operations, primarily reflecting:

•

An increase in sales to retail customers, primarily due to an increase in cooling degree days ($68 million); and

•

An increase from rate adjustment clauses ($63 million); partially offset by

•

A decrease in sales to customers due to the effect of changes in customer usage and other factors ($41 million); and

•

A $34 million increase from merchant generation operations, primarily due to increased generation output reflecting the addition of solar assets ($21 million) and at certain other merchant generation facilities ($14 million).

Other operations and maintenance decreased 8%, primarily reflecting:

•

A $52 million gain from an agreement to convey shale development rights underneath a natural gas storage field; and

•

The absence of charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities ($43 million).

These decreases were partially offset by:

•

A $26 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income; and

•

A $15 million net increase due to services performed for Atlantic Coast Pipeline and Blue Racer. These expenses are billed to these entities and do not significantly impact net income.

Other income decreased 84%, primarily due to lower realized gains (net of investment income) on nuclear decommissioning trust funds ($36 million), a decrease in earnings from rabbi trust investments ($7 million) and an increase in donations paid ($6 million).

Income tax expense increased 34%, primarily reflecting higher pre-tax income.

Year-To-Date 2015 vs. 2014

Net revenue increased 15%, primarily reflecting:

•

The absence of losses related to the repositioning of Dominion’s producer services business in the first quarter of 2014, reflecting the termination of natural gas trading and certain energy marketing activities ($319 million);

•

A $201 million increase from electric utility operations, primarily reflecting:

•

An increase from rate adjustment clauses ($213 million);

•

An increase in sales to retail customers, primarily due to an increase in cooling degree days ($103 million); partially offset by

•

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

•

A decrease in PJM ancillary revenues ($39 million); and

•

A decrease in sales to customers due to the effect of changes in customer usage and other factors ($19 million);

•

The absence of losses related to the retail electric energy marketing business which was sold in the first quarter of 2014 ($129 million);

•

A $58 million increase from merchant generation operations, primarily due to increased generation output reflecting the absence of planned outages at certain merchant generation facilities ($74 million) and the addition of solar assets ($43 million), partially offset by lower realized prices ($57 million);

•

A $58 million increase from regulated natural gas distribution operations, primarily due to an increase in rate adjustment clause revenue related to low income assistance programs ($26 million), an increase in AMR and PIR program revenues ($19 million) and various expansion projects being placed into service ($19 million); and

•

A $42 million increase from regulated natural gas transmission operations, primarily reflecting:

•

A $55 million increase in gas transportation and storage activities, primarily due to the addition of DCG ($42 million), decreased fuel costs ($23 million) and various expansion projects being placed into service ($23 million), partially offset by decreased regulated gas sales ($35 million); and

•

A $40 million net increase primarily due to services performed for Atlantic Coast Pipeline and Blue Racer; partially offset by

•

A $41 million decrease in NGL activities, primarily due to decreased prices.

Other operations and maintenance decreased 5%, primarily reflecting:

•

The absence of charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities ($325 million);

•

Gains from agreements to convey shale development rights underneath several natural gas storage fields ($123 million); and

•

A $66 million decrease in planned outage costs primarily due to a decrease in scheduled outage days at certain merchant generation facilities ($45 million) and non-nuclear utility generation facilities ($21 million).

These decreases were partially offset by:

•

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

•

A $76 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;

•

The absence of gains on the sale of assets to Blue Racer ($59 million);

•

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

•

A $40 million increase in utility nuclear refueling outage costs primarily due to the amortization of outage costs that were previously deferred pursuant to Virginia legislation enacted in April 2014;

•

A $39 million net increase due to services performed for Atlantic Coast Pipeline and Blue Racer. These expenses are billed to these entities and do not significantly impact net income;

•

A $26 million increase in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income; and

•

A $17 million increase due to the acquisition of DCG.

Other income decreased 23%, primarily due to lower realized gains (net of investment income) on nuclear decommissioning trust funds ($15 million), a decrease in earnings from rabbi trust investments ($9 million) and an increase in donations paid ($6 million).

Income tax expense increased 66%, primarily reflecting higher pre-tax income.

Segment Results of Operations

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


	Net Income attributable to Dominion									Diluted EPS
	2015			2014			$ Change			2015			2014			$ Change
(millions, except EPS)
Third Quarter
DVP	$	125		$	119		$	6		$	0.21		$	0.20		$	0.01
Dominion Generation		391			326			65			0.66			0.56			0.10
Dominion Energy		152			144			8			0.26			0.25			0.01

Primary operating segments		668			589			79			1.13			1.01			0.12
Corporate and Other		(75	)		(60	)		(15	)		(0.13	)		(0.11	)		(0.02	)

Consolidated	$	593		$	529		$	64		$	1.00		$	0.90		$	0.10

Year-To-Date
DVP	$	382		$	366		$	16		$	0.64		$	0.63		$	0.01
Dominion Generation		923			794			129			1.56			1.36			0.20
Dominion Energy		488			482			6			0.82			0.82			—

Primary operating segments		1,793			1,642			151			3.02			2.81			0.21
Corporate and Other		(251	)		(575	)		324			(0.42	)		(0.98	)		0.56

Consolidated	$	1,542		$	1,067		$	475		$	2.60		$	1.83		$	0.77

DVP

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


	Third Quarter							Year-To-Date
	2015		2014		% Change			2015		2014		% Change
Electricity delivered (million MWh)		22.6		21.9		3	%		65.6		63.6		3	%
Degree days (electric distribution service area):
Cooling		1,174		1,058		11			1,819		1,587		15
Heating		—		2		(100	)		2,578		2,548		1
Average electric distribution customer accounts (thousands)⁽¹⁾		2,526		2,501		1			2,522		2,496		1

(1)	Period average.

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


	Third Quarter 2015 vs. 2014 Increase (Decrease)						Year-To-Date 2015 vs. 2014 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	11		$	0.02		$	18		$	0.03
Other		(7	)		(0.01	)		—			—
FERC transmission equity return		10			0.02			30			0.04
Depreciation and amortization		(1	)		—			(6	)		(0.01	)
Other operations and maintenance expense		2			—			(12	)		(0.02	)
Other		(9	)		(0.02	)		(14	)		(0.02	)
Share dilution		—			—			—			(0.01	)

Change in net income contribution	$	6		$	0.01		$	16		$	0.01

Dominion Generation

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


	Third Quarter							Year-To-Date
	2015		2014		% Change			2015		2014		% Change
Electricity supplied (million MWh):
Utility		22.9		22.1		4	%		66.2		64.0		3	%
Merchant		7.6		7.2		6			20.6		19.4		6
Degree days (electric utility service area):
Cooling		1,174		1,058		11			1,819		1,587		15
Heating		—		2		(100	)		2,578		2,548		1
Average retail energy marketing customer accounts (thousands)⁽¹⁾⁽²⁾		1,319		1,196		10			1,285		1,298		(1	)

(1)	Period average.

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

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


	Third Quarter 2015 vs. 2014 Increase (Decrease)						Year-To-Date 2015 vs. 2014 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Merchant generation margin	$	19		$	0.04		$	39		$	0.06
Regulated electric sales:
Weather		30			0.05			45			0.08
Other		(16	)		(0.03	)		(7	)		(0.01	)
PJM ancillary services		(1	)		—			(15	)		(0.02	)
Rate adjustment clause equity return		1			—			22			0.04
Depreciation and amortization		(8	)		(0.01	)		(20	)		(0.03	)
Outage costs		1			—			15			0.02
Renewable energy investment tax credits⁽¹⁾		36			0.06			67			0.11
Other		3			—			(17	)		(0.03	)
Share dilution		—			(0.01	)		—			(0.02	)

Change in net income contribution	$	65		$	0.10		$	129		$	0.20

(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
	2015		2014		% Change			2015		2014		% Change
Gas distribution throughput (bcf):
Sales		2		2		—	%		21		23		(9	)%
Transportation		89		56		59			341		242		41
Heating degree days (gas distribution service area)		48		126		(62	)		4,191		4,242		(1	)
Average gas distribution customer accounts (thousands)⁽¹⁾:
Sales		234		236		(1	)		237		241		(2	)
Transportation		1,050		1,044		1			1,060		1,054		1

(1)	Period average.

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


	Third Quarter 2015 vs. 2014 Increase (Decrease)						Year-To-Date 2015 vs. 2014 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Blue Racer	$	1		$	—		$	(36)	⁽¹⁾	$	(0.06	)
Assignment of shale development rights		28			0.05			70			0.12
Noncontrolling interest ⁽²⁾		(3	)		—			(9	)		(0.01	)
Depreciation and amortization		(3	)		—			(11	)		(0.02	)
Gas distribution margin:
Weather		(1	)		—			—			—
Rate adjustment clauses		4			—			13			0.02
Other		5			0.01			10			0.02
Other operations and maintenance		(13	)		(0.02	)		(13	)		(0.02	)
Other		(10	)		(0.02	)		(18	)		(0.03	)
Share dilution		—			(0.01	)		—			(0.02	)

Change in net income contribution	$	8		$	0.01		$	6		$	—

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

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

Corporate and Other

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


	Third Quarter									Year-To-Date
	2015			2014			$ Change			2015			2014			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	(18	)	$	(33	)	$	15		$	(80	)	$	(435	)	$	355
Specific items attributable to corporate operations		—			17			(17	)		(2	)		(11	)		9

Total specific items		(18	)		(16	)		(2	)		(82	)		(446	)		364
Other corporate operations:
Renewable energy investment tax credits		5			35			(30	)		15			91			(76	)
Other		(62	)		(79	)		17			(184	)		(220	)		36

Total other corporate operations		(57	)		(44	)		(13	)		(169	)		(129	)		(40	)

Total net expense	$	(75	)	$	(60	)	$	(15	)	$	(251	)	$	(575	)	$	324
EPS impact	$	(0.13	)	$	(0.11	)	$	(0.02	)	$	(0.42	)	$	(0.98	)	$	0.56

Total Specific Items

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

Virginia Power

Results of Operations

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


	Third Quarter						Year-To-Date
	2015		2014		$ Change		2015		2014		$ Change
(millions)
Net income	$	385	$	314	$	71	$	900	$	707	$	193

Overview

Third Quarter 2015 vs. 2014

Net income increased 23%, primarily due to an increase in sales to retail customers, primarily due to an increase in cooling degree days, an increase from rate adjustment clauses, and the absence of charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities, partially offset by a decrease in sales to customers due to the effect of changes in customer usage and other factors.

Year-To-Date 2015 vs. 2014

Net income increased 27%, primarily due to the absence of charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities.

Analysis of Consolidated Operations

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


	Third Quarter							Year-To-Date
	2015		2014		$ Change			2015		2014		$ Change
(millions)
Operating revenue	$	2,058	$	2,053	$	5		$	6,008	$	5,765	$	243
Electric fuel and other energy-related purchases		554		649		(95	)		1,861		1,817		44
Purchased electric capacity		75		86		(11	)		259		261		(2	)

Net revenue		1,429		1,318		111			3,888		3,687		201

Other operations and maintenance		375		401		(26	)		1,216		1,375		(159	)
Depreciation and amortization		244		260		(16	)		713		695		18
Other taxes		69		63		6			212		205		7
Other income		13		24		(11	)		49		60		(11	)
Interest and related charges		116		101		15			332		311		21
Income tax expense		253		203		50			564		454		110

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

Third Quarter 2015 vs. 2014

Net revenue increased 8%, primarily reflecting an increase in sales to retail customers, primarily due to an increase in cooling degree days ($68 million) and an increase from rate adjustment clauses ($63 million), partially offset by a decrease in sales to customers due to the effect of changes in customer usage and other factors ($41 million).

Other operations and maintenance decreased 6%, primarily reflecting the absence of charges associated with Virginia legislation enacted in April 2014 relating to the development of a third nuclear unit located at North Anna and offshore wind facilities ($43 million), partially offset by a $26 million increase in certain electric transmission-related expenditures, which are primarily recovered through state and FERC rates and do not impact net income.

Other income decreased 46%, primarily reflecting a decrease in the equity component of AFUDC ($5 million), a decrease in amounts collectible from customers for taxes in connection with contributions in aid of construction ($3 million) and lower realized gains (net of investment income) on nuclear decommissioning trust funds ($2 million).

Interest and related charges increased 15%, primarily reflecting higher long-term debt interest expense resulting from debt issuances in October 2014 and May 2015.

Income tax expense increased 25%, primarily reflecting higher pre-tax income.

Year-To-Date 2015 vs. 2014

Net revenue increased 5%, primarily reflecting:

•

An increase from rate adjustment clauses ($213 million);

•

An increase in sales to retail customers, primarily due to an increase in cooling degree days ($103 million); partially offset by

•

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

•

A decrease in PJM ancillary revenues ($39 million); and

•

A decrease in sales to customers due to the effect of changes in customer usage and other factors ($19 million).

Other operations and maintenance decreased 12%, primarily reflecting:

•

A $21 million decrease in planned outage costs primarily due to a decrease in scheduled outage days at certain non-nuclear utility generation facilities.

These decreases were partially offset by:

•

A $76 million increase in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;

•

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

•

Other income decreased 18%, primarily reflecting a decrease in amounts collectible from customers for taxes in connection with contributions in aid of construction ($5 million) and a decrease in the equity component of AFUDC ($3 million).

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

Dominion Gas

Results of Operations

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


	Third Quarter						Year-To-Date
	2015		2014		$ Change		2015		2014		$ Change
(millions)
Net income	$	111	$	107	$	4	$	357	$	364	$	(7	)

Overview

Third Quarter 2015 vs. 2014

Net income increased 4%, primarily due to a gain from an agreement to convey shale development rights underneath a natural gas storage field, partially offset by the absence of gains on the sale of assets and higher interest expense.

Year-To-Date 2015 vs. 2014

Net income decreased 2%, primarily due to the absence of gains on the sale of assets to Blue Racer, a decrease in income from NGL activities and higher interest expense, partially offset by increased gains from agreements to convey shale development rights underneath several natural gas storage fields.

Analysis of Consolidated Operations

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


	Third Quarter							Year-To-Date
	2015		2014		$ Change			2015		2014		$ Change
(millions)
Operating revenue	$	365	$	391	$	(26	)	$	1,291	$	1,388	$	(97	)
Purchased gas		8		34		(26	)		103		247		(144	)
Other energy-related purchases		4		8		(4	)		17		29		(12	)

Net revenue		353		349		4			1,171		1,112		59

Other operations and maintenance		63		91		(28	)		261		253		8
Depreciation and amortization		53		50		3			157		146		11
Other taxes		35		31		4			127		117		10
Other income		4		5		(1	)		17		18		(1	)
Interest and related charges		18		7		11			53		19		34
Income tax expense		77		68		9			233		231		2

An analysis of Dominion Gas’ results of operations follows:

Third Quarter 2015 vs. 2014

Net revenue increased 1%, primarily reflecting:

•

An $8 million increase from regulated natural gas distribution operations, primarily due to an increase in off-system sales ($7 million) and an increase in AMR and PIR program revenues ($5 million), partially offset by a decrease in rate adjustment clause revenue related to low income assistance programs ($3 million); partially offset by

•

A $4 million decrease from regulated natural gas transmission operations, primarily reflecting:

•

A $15 million decrease in NGL activities, primarily due to decreased prices; and

•

Decreased regulated gas sales ($3 million); partially offset by

•

A $16 million net increase primarily due to services performed for Atlantic Coast Pipeline and Blue Racer.

Other operations and maintenance decreased 31%, primarily reflecting:

•

A $52 million gain from an agreement to convey shale development rights underneath a natural gas storage field; partially offset by

•

A $16 million net increase due to services performed for Atlantic Coast Pipeline and Blue Racer. These expenses are billed to these entities and do not significantly impact net income; and

•

The absence of gains on the sale of assets ($11 million).

Other taxes increased 13%, primarily due to increased investment resulting in higher property taxes.

Interest and related charges increased $11 million, primarily due to higher long-term debt interest expense resulting from debt issuances in December 2014.

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

Year-To-Date 2015 vs. 2014

Net revenue increased 5%, primarily reflecting:

•

A $1 million increase from regulated natural gas transmission operations, primarily reflecting:

•

A $13 million increase in gas transportation and storage activities, primarily due to decreased fuel costs ($23 million) and various expansion projects being placed into service ($23 million), partially offset by decreased regulated gas sales ($35 million); and

•

A $40 million net increase primarily due to services performed for Atlantic Coast Pipeline and Blue Racer; partially offset by

•

A $41 million decrease in NGL activities, primarily due to decreased prices.

Other operations and maintenance increased 3%, primarily reflecting:

•

A $40 million net increase due to services performed for Atlantic Coast Pipeline and Blue Racer. These expenses are billed to these entities and do not significantly impact net income;

•

The absence of gains on the sale of assets to Blue Racer ($59 million); partially offset by

•

Gains from agreements to convey shale development rights underneath several natural gas storage fields ($123 million).

Interest and related charges increased $34 million, primarily due to higher long-term debt interest expense resulting from debt issuances in December 2014.

Liquidity and Capital Resources

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

In September 2015, Dominion initiated a program to purchase from the market up to $50 million of common units representing limited partner interests in Dominion Midstream. The common units may be acquired by Dominion over the next 12 months at the discretion of management. During the third quarter of 2015, Dominion purchased approximately 77,000 common units for approximately $2 million. In October 2015, Dominion purchased approximately 478,000 additional common units for approximately $13 million.

At September 30, 2015, Dominion had $1.9 billion of unused capacity under its credit facilities.

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


	2015			2014
(millions)
Cash and cash equivalents at January 1	$	318		$	316
Cash flows provided by (used in):
Operating activities		3,453			2,410
Investing activities		(4,350	)		(3,533	)
Financing activities		817			1,025

Net decrease in cash and cash equivalents		(80	)		(98	)

Cash and cash equivalents at September 30	$	238		$	218

Operating Cash Flows

Net cash provided by Dominion’s operating activities increased $1.0 billion, primarily due to the absence of losses related to the repositioning of Dominion’s producer services business in 2014, higher deferred fuel cost recoveries in its Virginia jurisdiction, higher revenue from rate adjustment clauses, lower net margin collateral requirements, the impact from more favorable weather in 2015, and 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, 2014.

Credit Risk

Dominion’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion’s credit exposure as of September 30, 2015 for these activities. Gross credit exposure for each counterparty is calculated prior to the application of collateral and represents outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.


	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade⁽¹⁾	$	108	$	47	$	61
Non-investment grade⁽²⁾		1		—		1
No external ratings:
Internally rated—investment grade⁽³⁾		17		—		17
Internally rated—non-investment grade⁽⁴⁾		69		—		69

Total	$	195	$	47	$	148

(1)	Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 29% of the total net credit exposure.

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

(3)	The five largest counterparty exposures, combined, for this category represented approximately 11% of the total net credit exposure.

(4)	The five largest counterparty exposures, combined, for this category represented approximately 42% of the total net credit exposure.

Investing Cash Flows

Net cash used in Dominion’s investing activities increased $817 million, primarily due to Dominion’s acquisition of DCG in 2015, the absence of proceeds from the sale of Dominion’s electric retail energy marketing business, and higher acquisitions of solar development projects in 2015.

Financing Cash Flows and Liquidity

Dominion relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed further in Credit Ratings and Debt Covenants in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, the ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

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

In 2015, net cash provided by Dominion’s financing activities decreased $208 million, primarily reflecting lower net debt issuances, partially offset by the issuance of common stock through an at-the-market program.

See Note 15 to the Consolidated Financial Statements in this report for further information regarding Dominion’s credit facilities, liquidity and significant financing transactions.

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In the Credit Ratings section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, there is a discussion on the use of capital markets by Dominion as well as the impact of credit ratings on the accessibility and costs of using these markets. As of September 30, 2015, there have been no changes in Dominion’s credit ratings.

Debt Covenants

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

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

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

Use of Off-Balance Sheet Arrangements

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

Future Issues and Other Matters

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by, and subsequent to, the dates of Dominion’s Consolidated Financial Statements that may impact future results of operations, financial condition and/or cash flows. This section should be read in conjunction with Item 1. Business and Future Issues and Other Matters in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Future Issues and Other Matters in MD&A in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015.

Environmental Matters

Dominion is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. See Note 22 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Note 16 to the Consolidated Financial Statements in this report for additional information on various environmental matters.

In August 2015, the EPA issued final carbon standards for existing fossil fuel power plants. Known as the Clean Power Plan, the rule uses a set of measures for reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units and expanding renewable resources. The new rule requires states to impose standards of performance limits for existing fossil fuel-fired electric generating units or equivalent statewide intensity-based or mass-based CO₂ binding goals or limits. States are required to submit interim plans to the EPA by summer 2016 identifying how they will comply with the rule, with final plans due by September 2018. Dominion’s most recent integrated resources plan filed in July 2015 includes four alternative plans that represent plausible compliance strategies with the rule as proposed, and which include additional coal unit retirements and additional low or zero-carbon resources. However, until the state plans are developed and the EPA approves the plans, Dominion cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.

Legal Matters

See Item 3. Legal Proceedings in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, Notes 12 and 15 to the Consolidated Financial Statements and Item 1. Legal Proceedings in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 and Notes 12 and 16 to the Consolidated Financial Statements and Item 1. Legal Proceedings for the quarter ended June 30, 2015 and in this report for additional information on various legal matters.

Regulatory Matters

See Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014 and Note 12 in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015, June 30, 2015 and in this report for additional information on various regulatory matters.

DTI Gathering and Processing Facilities

In October 2015, DTI filed an application with FERC seeking authority to abandon by sale its gathering and processing facilities to Dominion Gathering and Processing, Inc., a newly-formed wholly-owned subsidiary of Dominion Gas. Pending approval by FERC, these gathering and processing facilities with a carrying value of approximately $430 million are expected to be transferred in the first half of 2016.

Atlantic Coast Pipeline

In September 2014, Dominion, along with Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc., announced the formation of Atlantic Coast Pipeline and its intent to construct an approximately 550-mile natural gas pipeline running from West Virginia through Virginia to North Carolina, which has an expected cost of $4.5 billion to $5.0 billion, excluding financing costs. An application requesting FERC authorization to construct and operate the project facilities was filed in September 2015. The project is expected to be in service in the fourth quarter of 2018.

Supply Header Project

In September 2014, DTI announced its intent to construct and operate the Supply Header Project which is expected to cost approximately $500 million and provide 1,500,000 Dths per day of firm transportation service to various customers including the Atlantic Coast Pipeline. In September 2015, DTI filed its application requesting FERC authorization to construct and operate the project facilities. The project is expected to be in service in the fourth quarter of 2018.

West Virginia Regulation

In September 2015, Hope requested approval of PREP from the West Virginia Commission. In the application, Hope proposed a projected capital investment for 2016 of $24 million as part of a total five-year projected capital investment of $158 million.

Ohio Regulation

In October 2015, East Ohio requested approval from the Ohio Commission to defer the operation and maintenance costs associated with implementing a proposed PSMP. The costs are not expected to exceed $15 million per year.

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 primarily hold commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products and Dominion Gas primarily holds commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of natural gas and other energy-related products.

The derivatives used to manage commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based financial derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on observable market prices.

A hypothetical 10% decrease in commodity prices of Dominion’s commodity-based financial derivative instruments would have resulted in an increase in fair value of approximately $68 million and $101 million as of September 30, 2015 and December 31, 2014, respectively. The decline in sensitivity is largely due to decreased commodity derivative activity and lower commodity prices.

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

A hypothetical 10% decrease in commodity prices of Dominion Gas’ commodity-based financial derivative instruments would have resulted in an increase in fair value of approximately $6 million and $2 million as of September 30, 2015 and December 31, 2014, respectively. The rise in sensitivity is largely due to increased commodity derivative activity.

The impact of a change in energy commodity prices on the Companies’ commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.

Interest Rate Risk

The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt and interest rate swaps designated under fair value hedging and outstanding for the Companies, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at September 30, 2015 or December 31, 2014.

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

As of September 30, 2015 Dominion, Virginia Power and Dominion Gas had $3.8 billion, $1.2 billion and $250 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $43 million, $30 million and $1 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at September 30, 2015. As of December 31, 2014, Dominion, Virginia Power and Dominion Gas had $4.1 billion, $1.5 billion and $250 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $46 million, $25 million and $2 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2014.

The impact of a change in interest rates on the Companies’ interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.

Investment Price Risk

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

Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $134 million for the nine months ended September 30, 2015 and 2014 and $176 million for the year ended December 31, 2014. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on these investments of $260 million for the nine months ended September 30, 2015, and a net increase in unrealized gains on these investments of $86 million and $172 million for the nine months ended September 30, 2014 and for the year ended December 31, 2014, respectively.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $67 million, $58 million and $77 million for the nine months ended September 30, 2015 and 2014 and for the year ended December 31, 2014, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded, in AOCI and regulatory liabilities, a net decrease in unrealized gains on these investments of $123 million for the nine months ended September 30, 2015, and a net increase in unrealized gains on these investments of $47 million and $87 million for the nine months ended September 30, 2014 and for the year ended December 31, 2014, respectively.

Dominion sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power and Dominion Gas employees participate in these plans. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

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.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

•

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

•

Notes 12 and 15 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, which information is incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which the Companies are a party.

•

Notes 12 and 16 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, which information is incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which the Companies are a party.

•

Notes 12 and 16 in this report, which information is incorporated herein by reference, for discussion of various environmental and other regulatory proceedings to which the Companies are a party.

ITEM 1A. RISK FACTORS

The Companies businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond the Companies’ control. A number of these risk factors have been identified in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014, which should be taken into consideration when reviewing the information contained in this report. There have been no material changes with regard to the risk factors previously disclosed in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.

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

Dominion

ISSUER PURCHASES OF EQUITY SECURITIES


Period	Total Number of Shares (or Units) Purchased⁽¹⁾		Average Price Paid per Share (or Unit)⁽²⁾		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs⁽³⁾
7/1/15-7/31/15		—	$	—		—	19,629,059 shares/ $1.18 billion
8/1/15-8/31/15		495		71.70		—	19,629,059 shares/ $1.18 billion
9/1/15-9/30/15		1,228		67.81		—	19,629,059 shares/ $1.18 billion

Total		1,723	$	68.93		—	19,629,059 shares/ $1.18 billion

(1)	In August and September 2015, 495 shares and 1,228 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 BOD in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion BOD was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion.

ITEM 6. EXHIBITS


Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas

3.1.a	Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).	X

3.1.b	Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255).		X

3.1.c	Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).			X

3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective May 6, 2015 (Exhibit 3.1, Form 8-K filed May 6, 2015, File No. 1-8489).	X

3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).		X

3.2.c	Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066).			X

4	Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.	X	X	X

4.1	Indenture, dated as of June 1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489); First Supplemental Indenture, dated as of June 1, 2015 (Exhibit 4.2, Form 8-K filed June 15, 2015, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2015 (Exhibit 4.2, Form 8-K filed September 24, 2015, 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, Virginia Electric and Power Company’s and Dominion Gas Holdings, LLC’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, filed on November 3, 2015, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Comprehensive Income (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.	X	X	X

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SIGNATURE

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


				DOMINION RESOURCES, INC.
				Registrant

November 3, 2015				/s/ Michele L. Cardiff
				Michele L. Cardiff
				Vice President, Controller and Chief Accounting Officer

				VIRGINIA ELECTRIC AND POWER COMPANY
				Registrant

November 3, 2015				/s/ Michele L. Cardiff
				Michele L. Cardiff
				Vice President, Controller and Chief Accounting Officer

				DOMINION GAS HOLDINGS, LLC
				Registrant

November 3, 2015				/s/ Michele L. Cardiff
				Michele L. Cardiff
				Vice President, Controller and Chief Accounting Officer

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EXHIBIT INDEX


Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas

3.1.a	Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).	X

3.1.b	Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255).		X

3.1.c	Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).			X

3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective May 6, 2015 (Exhibit 3.1, Form 8-K filed May 6, 2015, File No. 1-8489).	X

3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).		X

3.2.c	Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066).			X

4	Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.	X	X	X

4.1	Indenture, dated as of June 1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489); First Supplemental Indenture, dated as of June 1, 2015 (Exhibit 4.2, Form 8-K filed June 15, 2015, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2015 (Exhibit 4.2, Form 8-K filed September 24, 2015, 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

102



32.b	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X

32.c	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).			X

99	Condensed consolidated earnings statements (filed herewith).	X	X	X

101	The following financial statements from Dominion Resources, Inc.’s, Virginia Electric and Power Company’s and Dominion Gas Holdings, LLC’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, filed on November 3, 2015, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Comprehensive Income (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.	X	X	X

103