UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended June 30, 2016

or

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

For the transition period from                      to                     

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

120 Tredegar Street

Richmond, Virginia 23219

(804) 819-2000

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

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

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

Dominion Gas Holdings, LLC    Yes  x    No  ¨

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

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

Dominion Gas Holdings, LLC    Yes  x    No  ¨

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

Dominion Resources, Inc.

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

Virginia Electric and Power Company

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

Dominion Gas Holdings, LLC

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

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

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

Dominion Gas Holdings, LLC    Yes  ¨    No  x

At July 15, 2016, the latest practicable date for determination, Dominion Resources, Inc. had 625,763,030 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		79
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		93
Item 4.	Controls and Procedures		95
	PART II. Other Information
Item 1.	Legal Proceedings		96
Item 1A.	Risk Factors		96
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		96
Item 6.	Exhibits		97

2

GLOSSARY OF TERMS

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

Abbreviation or Acronym	Definition
2013 Equity Units	Dominion’s 2013 Series A Equity Units and 2013 Series B Equity Units issued in June 2013
2014 Equity Units	Dominion’s 2014 Series A Equity Units issued in July 2014
AFUDC	Allowance for funds used during construction
AMR	Automated meter reading program deployed by East Ohio
AOCI	Accumulated other comprehensive income (loss)
APCo	Appalachian Power Company
AROs	Asset retirement obligations
ARP	Acid Rain Program, a market-based initiative for emissions allowance trading, established pursuant to Title IV of the CAA
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion, Duke Energy Corporation, Piedmont Natural Gas Company, Inc. and AGL Resources Inc.
BACT	Best available control technology
bcf	Billion cubic feet
Bear Garden	A 590 MW combined cycle, natural gas-fired power station in Buckingham County, Virginia
Blue Racer	Blue Racer Midstream, LLC, a joint venture between Dominion and Caiman Energy II, LLC
BREDL	Blue Ridge Environmental Defense League
Brunswick County	A 1,358 MW combined cycle, natural gas-fired power station in Brunswick County, Virginia
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAISO	California Independent System Operator
CCR	Coal combustion residual
CEO	Chief Executive Officer
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund
CFO	Chief Financial Officer
CO2	Carbon dioxide
COL	Combined Construction Permit and Operating License
Columbia to Eastover Project	Project to provide 15,800 Dths/day of firm transportation service from an existing interconnect with Southern Natural Gas Company, LLC in Aiken County, South Carolina and provide for a receipt point change of 2,200 Dths/day under an existing contract from an existing interconnect with Transco in Cherokee County, South Carolina for a total 18,000 Dths/day, to a new delivery point for the International Paper Company at its pulp and paper mill known as the Eastover Plant in Richland County, South Carolina
Companies	Dominion, Virginia Power and Dominion Gas, collectively
Cooling degree days	Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
Cove Point	Dominion Cove Point LNG, LP
CPCN	Certificate of Public Convenience and Necessity
CSAPR	Cross State Air Pollution Rule
CWA	Clean Water Act
DCG	Dominion Carolina Gas Transmission, LLC (successor by statutory conversion to and formerly known as Carolina Gas Transmission Corporation)
DEI	Dominion Energy, Inc.
Dominion	The legal entity, Dominion Resources, Inc., one or more of its consolidated subsidiaries (other than Virginia Power and Dominion Gas) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries
Dominion Gas	The legal entity, Dominion Gas Holdings, LLC, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Gas Holdings, LLC and its consolidated subsidiaries
Dominion Iroquois	Dominion Iroquois, Inc., which, as of May 2016, holds a 24.07% noncontrolling partnership interest in Iroquois
Dominion Midstream	The legal entity, Dominion Midstream Partners, LP, one or more of its consolidated subsidiaries, Cove Point Holdings, Iroquois GP Holding Company, LLC and DCG (beginning April 1, 2015), or the entirety of Dominion Midstream Partners, LP, and its consolidated subsidiaries
DRS	Dominion Resources Services, Inc.

3

Abbreviation or Acronym	Definition
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
EPA	Environmental Protection Agency
EPS	Earnings per share
FERC	Federal Energy Regulatory Commission
Four Brothers	Four Brothers Solar, LLC, a limited liability company owned by Dominion and Four Brothers Holdings, LLC, a wholly-owned subsidiary of SunEdison
Fowler Ridge	A wind-turbine facility joint venture between Dominion and BP Wind Energy North America Inc. in Benton County, Indiana
FTRs	Financial transmission rights
GAAP	United States generally accepted accounting principles
Gal	Gallon
GHG	Greenhouse gas
Granite Mountain	Granite Mountain Holdings, LLC, a limited liability company owned by Dominion and Granite Mountain Renewables, LLC, a wholly-owned subsidiary of SunEdison
Greensville County	An approximately 1,588 MW proposed natural gas-fired combined-cycle power station under construction in Greensville County, Virginia
Heating degree days	Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day
Hope	Hope Gas, Inc., doing business as Dominion Hope
Iron Springs	Iron Springs Holdings, LLC, a limited liability company owned by Dominion and Iron Springs Renewables, LLC, a wholly-owned subsidiary of SunEdison
Iroquois	Iroquois Gas Transmission System, L.P.
ISO-NE	Independent System Operator New England
July 2016 hybrids	2016 Series A Enhanced Junior Subordinated Notes due 2076
June 2006 hybrids	2006 Series A Enhanced Junior Subordinated Notes due 2066
kV	Kilovolt
Liquefaction Project	A natural gas export/liquefaction facility currently under construction by Cove Point
LNG	Liquefied natural gas
MATS	Utility Mercury and Air Toxics Standard Rule
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MGD	Million gallons a day
MISO	Midcontinent Independent Transmission System Operator, Inc.
MW	Megawatt
MWh	Megawatt hour
NedPower	A wind-turbine facility joint venture between Dominion and Shell Wind Energy, Inc. in Grant County, West Virginia
NGLs	Natural gas liquids
NOx	Nitrogen oxide
NRC	Nuclear Regulatory Commission
NSPS	New Source Performance Standards
Ohio Commission	Public Utilities Commission of Ohio
Order 1000	Order issued by FERC adopting new requirements for electric transmission planning, cost allocation and development
PIPP	Percentage of Income Payment Plan deployed by East Ohio
PIR	Pipeline Infrastructure Replacement program deployed by East Ohio
PJM	PJM Interconnection, L.L.C.
ppb	Parts-per-billion
PREP	Pipeline Replacement and Expansion Program, a program of replacing, upgrading and expanding natural gas utility infrastructure to be deployed by Hope
PSD	Prevention of Significant Deterioration

4

Abbreviation or Acronym	Definition
Questar	The legal entity, Questar Corporation, one or more of its consolidated subsidiaries, or operating segments, or the entirety of Questar Corporation and its consolidated subsidiaries
Questar Combination	Agreement and plan of merger entered on January 31, 2016 between Dominion and Questar in which Questar will become a wholly-owned subsidiary of Dominion upon closing
REIT	Real estate investment trust
Rider B	A rate adjustment clause associated with the recovery of costs related to the conversion of three of Virginia Power’s coal-fired power stations to biomass
Rider BW	A rate adjustment clause associated with the recovery of costs related to Brunswick County
Rider GV	A rate adjustment clause associated with the recovery of costs related to Greensville County
Rider R	A rate adjustment clause associated with the recovery of costs related to Bear Garden
Rider S	A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center
Rider T1	A rate adjustment clause to recover the difference between revenues produced from transmission rates included in base rates, and the new total revenue requirement developed annually for the rate years effective September 1
Rider US-2	A rate adjustment clause associated with the recovery of costs related to Woodland, Scott Solar and Whitehouse
Rider W	A rate adjustment clause associated with the recovery of costs related to Warren County
ROE	Return on equity
RSN	Remarketable subordinated note
Scott Solar	An approximately 17 MW proposed utility-scale solar power station in Powhatan County, Virginia
SEC	Securities and Exchange Commission
September 2006 hybrids	2006 Series B Enhanced Junior Subordinated Notes due 2066
SO2	Sulfur dioxide
Standard & Poor’s	Standard & Poor’s Ratings Services, a division of McGraw Hill Financial, Inc.
SunEdison	The legal entity, SunEdison, Inc., one or more of its consolidated subsidiaries (including Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of SunEdison, Inc. and its consolidated subsidiaries
Terra Nova Renewable Partners	A partnership between SunEdison and institutional investors advised by J.P. Morgan Asset Management-Global Real Assets
Three Cedars	Granite Mountain and Iron Springs, collectively
TransCanada	The legal entity, TransCanada Corporation, one or more of its consolidated subsidiaries, or operating segments, or the entirety of TransCanada Corporation and its consolidated subsidiaries
UAO	Unilateral Administrative Order
UEX Rider	Uncollectible Expense Rider deployed by East Ohio
VDEQ	Virginia Department of Environmental Quality
VEBA	Voluntary Employees’ Beneficiary Association
VIE	Variable interest entity
Virginia City Hybrid Energy Center	A 610 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County, Virginia
Virginia Commission	Virginia State Corporation Commission
Virginia Power	The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power and its consolidated subsidiaries
VOC	Volatile organic compounds
Warren County	A 1,342 MW combined-cycle, natural gas-fired power station in Warren County, Virginia
Whitehouse	An approximately 20 MW proposed utility-scale solar power station in Louisa County, Virginia
Woodland	An approximately 19 MW proposed utility-scale solar power station in Isle of Wight County, Virginia

5

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
(millions, except per share amounts)
Operating Revenue	$	2,598	$	2,747	$	5,519	$	6,156
Operating Expenses
Electric fuel and other energy-related purchases		551		591		1,185		1,544
Purchased electric capacity		45		90		113		184
Purchased gas		56		111		175		361
Other operations and maintenance		665		709		1,368		1,311
Depreciation, depletion and amortization		361		339		712		682
Other taxes		139		134		303		299
Total operating expenses		1,817		1,974		3,856		4,381
Income from operations		781		773		1,663		1,775
Other income		72		56		126		116
Interest and related charges		239		221		465		444
Income from operations including noncontrolling interests before income tax expense		614		608		1,324		1,447
Income tax expense		152		190		331		489
Net Income Including Noncontrolling Interests		462		418		993		958
Noncontrolling Interests		10		5		17		9
Net Income Attributable to Dominion	$	452	$	413	$	976	$	949
Earnings Per Common Share
Net income attributable to Dominion - Basic	$	0.73	$	0.70	$	1.61	$	1.61
Net income attributable to Dominion - Diluted		0.73		0.70		1.61		1.60
Dividends Declared Per Common Share	$	0.7000	$	0.6475	$	1.4000	$	1.2950

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

6

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
(millions)
Net income including noncontrolling interests	$	462		$	418		$	993		$	958
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		(11	)		92			42			34
Changes in unrealized net gains (losses) on investment securities(2)		26			(11	)		41			4
Changes in unrecognized pension and other postretirement benefit costs(3)		—			3			—			3
Amounts reclassified to net income:
Net derivative gains-hedging activities(4)		(44	)		(61	)		(107	)		(2	)
Net realized gains on investment securities(5)		(8	)		(12	)		(10	)		(33	)
Net pension and other postretirement benefit costs(6)		8			12			16			25
Changes in other comprehensive loss from equity method investees(7)		(1	)		—			(1	)		(1	)
Total other comprehensive income (loss)		(30	)		23			(19	)		30
Comprehensive income including noncontrolling interests		432			441			974			988
Comprehensive income attributable to noncontrolling interests		10			5			17			9
Comprehensive income attributable to Dominion	$	422		$	436		$	957		$	979

(1) Net of $7 million and $(59) million tax for the three months ended June 30, 2016 and 2015, respectively, and net of $(26) million and $(19) million tax for the six months ended June 30, 2016 and 2015, respectively.

(2) Net of $(15) million and $6 million tax for the three months ended June 30, 2016 and 2015, respectively, and net of $(25) million and $(5) million tax for the six months ended June 30, 2016 and 2015, respectively.

(3) Net of $— million and $3 million tax for the three months ended June 30, 2016 and 2015, respectively, and net of $—- million and $3 million tax for the six months ended June 30, 2016 and 2015, respectively.

(4) Net of $28 million and $41 million tax for the three months ended June 30, 2016 and 2015, respectively, and net of $67 million and $2 million tax for the six months ended June 30, 2016 and 2015, respectively.

(5) Net of $5 million and $8 million tax for the three months ended June 30, 2016 and 2015, respectively, and net of $6 million and $20 million tax for the six months ended June 30, 2016 and 2015, respectively.

(6) Net of $(6) million and $(9) million tax for the three months ended June 30, 2016 and 2015, respectively, and net of $(12) million and $(18) million tax for the six months ended June 30, 2016 and 2015, respectively.

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

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

7

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,      2016			December 31, 2015(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	377		$	607
Restricted cash and cash equivalents		516			17
Customer receivables (less allowance for doubtful accounts of $19 and $32)		1,140			1,200
Other receivables (less allowance for doubtful accounts of $3 and $2)		139			169
Inventories		1,351			1,348
Prepayments		143			198
Other		477			650
Total current assets		4,143			4,189
Investments
Nuclear decommissioning trust funds		4,331			4,183
Investment in equity method affiliates		1,372			1,320
Other		277			271
Total investments		5,980			5,774
Property, Plant and Equipment
Property, plant and equipment		60,490			57,776
Accumulated depreciation, depletion and amortization		(16,808	)		(16,222	)
Total property, plant and equipment, net		43,682			41,554
Deferred Charges and Other Assets
Goodwill		3,294			3,294
Pension and other postretirement benefit assets		1,017			943
Regulatory assets		2,150			1,865
Other		1,103			1,029
Total deferred charges and other assets		7,564			7,131
Total assets	$	61,369		$	58,648

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

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

8

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	June 30,      2016			December 31, 2015(1)
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	1,348		$	1,825
Short-term debt		3,437			3,509
Accounts payable		589			726
Accrued interest, payroll and taxes		561			515
Other(2)		1,331			1,544
Total current liabilities		7,266			8,119
Long-Term Debt
Long-term debt		21,406			20,048
Junior subordinated notes		2,399			1,340
Remarketable subordinated notes		982			2,080
Total long-term debt		24,787			23,468
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		7,666			7,414
Asset retirement obligations		1,941			1,887
Regulatory liabilities		2,318			2,285
Other		1,939			1,873
Total deferred credits and other liabilities		13,864			13,459
Total liabilities		45,917			45,046
Commitments and Contingencies (see Note 15)
Equity
Common stock – no par(3)		8,160			6,680
Retained earnings		6,585			6,458
Accumulated other comprehensive loss		(493	)		(474	)
Total common shareholders’ equity		14,252			12,664
Noncontrolling interests		1,200			938
Total equity		15,452			13,602
Total liabilities and equity	$	61,369		$	58,648

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

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

(3) 1 billion shares authorized; 617 million shares and 596 million shares outstanding at June 30, 2016 and December 31, 2015, respectively.

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

9

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Common Stock					Dominion Shareholders
	Shares		Amount			Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Shareholders’ Equity			Noncontrolling Interests			Total Equity
(millions)
December 31, 2015		596	$	6,680		$	6,458		$	(474	)	$	12,664		$	938		$	13,602
Net income including noncontrolling interests							976						976			17			993
Contributions from SunEdison to Four Brothers and Three Cedars													—			162			162
Sale of interest in merchant solar projects				22									22			117			139
Purchase of Dominion Midstream common units				(2	)								(2	)		(11	)		(13	)
Issuance of common stock		21		1,458									1,458						1,458
Stock awards (net of change in unearned compensation)				6									6						6
Dividends and distributions							(849	)					(849	)		(23	)		(872	)
Other comprehensive loss, net of tax										(19	)		(19	)					(19	)
Other				(4	)								(4	)					(4	)
June 30, 2016		617	$	8,160		$	6,585		$	(493	)	$	14,252		$	1,200		$	15,452

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

10

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,	2016			2015
(millions)
Operating Activities
Net income including noncontrolling interests	$	993		$	958
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)		853			822
Deferred income taxes and investment tax credits		275			399
Gains on the sales of assets and equity method investment in Iroquois		(45	)		(71	)
Other adjustments		(27	)		(18	)
Changes in:
Accounts receivable		82			214
Inventories		(3	)		47
Deferred fuel and purchased gas costs, net		114			28
Prepayments		55			47
Accounts payable		(92	)		(173	)
Accrued interest, payroll and taxes		46			(41	)
Margin deposit assets and liabilities		(13	)		186
Other operating assets and liabilities		(220	)		(238	)
Net cash provided by operating activities		2,018			2,160
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(3,160	)		(2,370	)
Acquisition of solar development projects		—			(230	)
Acquisition of DCG		—			(497	)
Proceeds from sales of securities		709			580
Purchases of securities		(752	)		(553	)
Restricted cash and cash equivalents		(500	)		—
Proceeds from assignments of shale development rights		5			28
Other		(27	)		(42	)
Net cash used in investing activities		(3,725	)		(3,084	)
Financing Activities
Repayment of short-term debt, net		(72	)		(153	)
Repayment and repurchase of short-term notes		(600	)		—
Issuance of long-term debt		1,930			1,200
Repayment and repurchase of long-term debt		(500	)		(8	)
Proceeds from sale of interest in merchant solar projects		117			—
Contributions from SunEdison to Four Brothers and Three Cedars		162			—
Issuance of common stock		1,458			647
Common dividend payments		(849	)		(765	)
Other		(169	)		(44	)
Net cash provided by financing activities		1,477			877
Decrease in cash and cash equivalents		(230	)		(47	)
Cash and cash equivalents at beginning of period		607			318
Cash and cash equivalents at end of period	$	377		$	271
Supplemental Cash Flow Information
Significant noncash investing and financing activities(1):
Accrued capital expenditures	$	257		$	319

(1) See Note 14 for noncash financing activities related to the remarketing of RSNs.

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

11

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
(millions)
Operating Revenue(1)	$	1,776	$	1,813	$	3,666	$	3,950
Operating Expenses
Electric fuel and other energy-related purchases(1)		475		497		1,011		1,307
Purchased electric capacity		45		90		113		184
Other operations and maintenance:
Affiliated suppliers		64		69		165		144
Other		322		376		671		697
Depreciation and amortization		247		231		495		469
Other taxes		70		69		144		143
Total operating expenses		1,223		1,332		2,599		2,944
Income from operations		553		481		1,067		1,006
Other income		18		21		34		36
Interest and related charges		113		108		227		216
Income before income tax expense		458		394		874		826
Income tax expense		178		148		331		311
Net Income	$	280	$	246	$	543	$	515

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

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

12

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
(millions)
Net income	$	280		$	246		$	543		$	515
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		(6	)		7			(15	)		3
Changes in unrealized net gains on nuclear decommissioning trust funds(2)		3			—			6			1
Amounts reclassified to net income:
Net derivative losses-hedging activities(3)		—			—			—			1
Net realized gains on nuclear decommissioning trust funds(4)		(1	)		(2	)		(1	)		(3	)
Total other comprehensive income (loss)		(4	)		5			(10	)		2
Comprehensive income	$	276		$	251		$	533		$	517

(1) Net of $4 million and $(4) million tax for the three months ended June 30, 2016 and 2015, respectively, and net of $9 million and $(2) million tax for the six months ended June 30, 2016 and 2015, respectively.

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

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

(4) Net of $1 million tax for both the three months ended June 30, 2016 and 2015, and net of $1 million tax for both the six months ended June 30, 2016 and 2015.

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

13

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,      2016			December 31, 2015(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	61		$	18
Customer receivables (less allowance for doubtful accounts of $13 and $27)		837			822
Other receivables (less allowance for doubtful accounts of $1 at both dates)		79			109
Affiliated receivables		2			296
Inventories (average cost method)		860			873
Prepayments		73			38
Regulatory assets		193			326
Other(2)		39			22
Total current assets		2,144			2,504
Investments
Nuclear decommissioning trust funds		2,030			1,945
Other		4			3
Total investments		2,034			1,948
Property, Plant and Equipment
Property, plant and equipment		38,734			37,639
Accumulated depreciation and amortization		(12,076	)		(11,708	)
Total property, plant and equipment, net		26,658			25,931
Deferred Charges and Other Assets
Regulatory assets		966			667
Other(2)		591			515
Total deferred charges and other assets		1,557			1,182
Total assets	$	32,393		$	31,565

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

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

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

14

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	June 30,      2016		December 31, 2015(1)
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	99	$	476
Short-term debt		1,423		1,656
Accounts payable		311		366
Payables to affiliates		74		73
Affiliated current borrowings		—		376
Accrued interest, payroll and taxes		229		190
Regulatory liabilities		112		35
Other(2)		585		558
Total current liabilities		2,833		3,730
Long-Term Debt		9,562		8,892
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		4,885		4,654
Asset retirement obligations		1,154		1,104
Regulatory liabilities		1,956		1,929
Other(2)		829		615
Total deferred credits and other liabilities		8,824		8,302
Total liabilities		21,219		20,924
Commitments and Contingencies (see Note 15)
Common Shareholder’s Equity
Common stock – no par(3)		5,738		5,738
Other paid-in capital		1,113		1,113
Retained earnings		4,293		3,750
Accumulated other comprehensive income		30		40
Total common shareholder’s equity		11,174		10,641
Total liabilities and shareholder’s equity	$	32,393	$	31,565

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

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

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

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

15

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,	2016			2015
(millions)
Operating Activities
Net income	$	543		$	515
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		589			555
Deferred income taxes and investment tax credits		228			13
Other adjustments		(11	)		(6	)
Changes in:
Accounts receivable		7			40
Affiliated receivables and payables		295			1
Inventories		13			25
Prepayments		(35	)		229
Deferred fuel expenses, net		105			(9	)
Accounts payable		(10	)		(9	)
Accrued interest, payroll and taxes		39			38
Other operating assets and liabilities		(61	)		2
Net cash provided by operating activities		1,702			1,394
Investing Activities
Plant construction and other property additions		(1,226	)		(1,292	)
Purchases of nuclear fuel		(78	)		(67	)
Proceeds from sales of securities		347			209
Purchases of securities		(373	)		(222	)
Other		(6	)		(27	)
Net cash used in investing activities		(1,336	)		(1,399	)
Financing Activities
Issuance (repayment) of short-term debt, net		(233	)		80
Repayment of affiliated current borrowings, net		(376	)		(427	)
Issuance of long-term debt		750			700
Repayment of long-term debt		(457	)		(6	)
Common dividend payments to parent		—			(270	)
Other		(7	)		(5	)
Net cash provided by (used in) financing activities		(323	)		72
Increase in cash and cash equivalents		43			67
Cash and cash equivalents at beginning of period		18			15
Cash and cash equivalents at end of period	$	61		$	82
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	142		$	117

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

16

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
(millions)
Operating Revenue(1)	$	368	$	395	$	799	$	926
Operating Expenses
Purchased gas(1)		16		21		50		95
Other energy-related purchases		1		7		4		13
Other operations and maintenance:
Affiliated suppliers		16		17		43		38
Other		58		107		155		160
Depreciation and amortization		52		53		95		104
Other taxes		39		37		91		92
Total operating expenses		182		242		438		502
Income from operations		186		153		361		424
Other income		9		4		15		13
Interest and related charges		23		18		45		35
Income from operations before income taxes		172		139		331		402
Income tax expense		67		54		128		156
Net Income	$	105	$	85	$	203	$	246

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

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

17

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
(millions)
Net income	$	105		$	85		$	203		$	246
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities(1)		(9	)		3			(15	)		(1	)
Amounts reclassified to net income:
Net derivative gains-hedging activities(2)		—			(1	)		(2	)		(1	)
Net pension and other postretirement benefit costs(3)		1			1			1			2
Total other comprehensive income (loss)		(8	)		3			(16	)		—
Comprehensive income	$	97		$	88		$	187		$	246

(1) Net of $4 million and $(1) million tax for the three months ended June 30, 2016 and 2015, respectively, and net of $8 million and $1 million tax for the six months ended June 30, 2016 and 2015, respectively.

(2) Net of $(2) million and $— million tax for the three months ended June 30, 2016 and 2015, respectively, and net of $— million tax for both the six months ended June 30, 2016 and 2015.

(3) Net of $— million and $(1) million tax for the three months ended June 30, 2016 and 2015, respectively, and net of $(1) million and $(2) million tax for the six months ended June 30, 2016 and 2015, respectively.

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

18

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,      2016			December 31, 2015(1)
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	226		$	13
Customer receivables (less allowance for doubtful accounts of $1 at both dates)(2)		176			219
Other receivables (less allowance for doubtful accounts of $2 at both dates)(2)		11			7
Affiliated receivables		6			98
Inventories		90			78
Prepayments		59			88
Other(2)		56			63
Total current assets		624			566
Investments		99			104
Property, Plant and Equipment
Property, plant and equipment		10,053			9,693
Accumulated depreciation and amortization		(2,766	)		(2,690	)
Total property, plant and equipment, net		7,287			7,003
Deferred Charges and Other Assets
Goodwill		542			542
Pension and other postretirement benefit assets(2)		1,579			1,510
Other(2)		604			583
Total deferred charges and other assets		2,725			2,635
Total assets	$	10,735		$	10,308

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

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

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

19

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)

	June 30,      2016			December 31, 2015(1)
(millions)
LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	400		$	400
Short-term debt		238			391
Accounts payable		124			201
Payables to affiliates		17			22
Affiliated current borrowings		—			95
Accrued interest, payroll and taxes		155			183
Other(2)		161			183
Total current liabilities		1,095			1,475
Long-Term Debt		3,541			2,869
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,331			2,214
Other(2)		412			432
Total deferred credits and other liabilities		2,743			2,646
Total liabilities		7,379			6,990
Commitments and Contingencies (see Note 15)
Equity
Membership interests		3,471			3,417
Accumulated other comprehensive loss(2)		(115	)		(99	)
Total equity		3,356			3,318
Total liabilities and equity	$	10,735		$	10,308

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

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

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

20

DOMINION GAS HOLDINGS, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Six Months Ended June 30,	2016			2015
(millions)
Operating Activities
Net income	$	203		$	246
Adjustments to reconcile net income to net cash provided by operating activities:
Gains on the sales of assets and equity method investment in Iroquois		(45	)		(71	)
Depreciation and amortization		95			104
Deferred income taxes and investment tax credits		125			55
Other adjustments		4			—
Changes in:
Accounts receivable		39			106
Affiliated receivables and payables		87			(15	)
Deferred purchased gas costs, net		11			28
Prepayments		29			111
Accounts payable		(75	)		(132	)
Accrued interest, payroll and taxes		(28	)		(54	)
Other operating assets and liabilities		(120	)		(85	)
Net cash provided by operating activities		325			293
Investing Activities
Plant construction and other property additions		(393	)		(292	)
Proceeds from sale of equity method investment in Iroquois		7			—
Proceeds from assignments of shale development rights		5			28
Other		(5	)		(6	)
Net cash used in investing activities		(386	)		(270	)
Financing Activities
Issuance (repayment) of short-term debt, net		(153	)		360
Issuance of long-term debt		680			—
Repayment of affiliated current borrowings, net		(95	)		(216	)
Distribution payments to parent		(150	)		(164	)
Other		(8	)		(1	)
Net cash provided by (used in) financing activities		274			(21	)
Increase in cash and cash equivalents		213			2
Cash and cash equivalents at beginning of period		13			9
Cash and cash equivalents at end of period	$	226		$	11
Supplemental Cash Flow Information
Significant noncash investing activities:
Accrued capital expenditures	$	42		$	37

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

21

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Gas. Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Dominion Gas is a holding company that conducts business activities through a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution operations in Ohio, and gas gathering and processing activities primarily in West Virginia, Ohio and Pennsylvania. Dominion Gas’ principal wholly-owned subsidiaries are DTI, East Ohio and Dominion Iroquois. In August 2016, DTI transferred its gathering and processing facilities to Dominion Gathering and Processing, Inc., a newly-formed wholly-owned subsidiary of Dominion Gas.

Note 2. Significant Accounting Policies

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

In the Companies’ opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position as of June 30, 2016, their results of operations for the three and six months ended June 30, 2016 and 2015, their cash flows for the six months ended June 30, 2016 and 2015 and Dominion’s statement of equity for the six months ended June 30, 2016. Such adjustments are normal and recurring in nature unless otherwise noted.

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

The Companies’ accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. As of June 30, 2016, Dominion owns the general partner and 64.8% of the limited partner interests in Dominion Midstream. The public’s ownership interest in Dominion Midstream is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. Also, as of June 30, 2016, Dominion owns 50% of the units in and consolidates Four Brothers and Three Cedars. SunEdison’s ownership interest in Four Brothers and Three Cedars, as well as Terra Nova Renewable Partners’ 33% interest in certain Dominion merchant solar projects, is reflected as noncontrolling interest in Dominion’s Consolidated Financial Statements. See Note 3 for further information on transactions with SunEdison.

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

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

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

Note 3. Acquisitions and Dispositions

Dominion

Proposed Acquisition of Questar

Pursuant to the terms of the Questar Combination announced in February 2016, upon closing, each share of Questar common stock issued and outstanding immediately prior to the closing will be converted automatically into the right to receive $25 in cash per share, or approximately $4.4 billion in total. In addition, Questar’s debt, which currently totals approximately $1.5 billion is expected to remain outstanding. Dominion entered into agreements with several of its lending banks pursuant to

22

which they have unfunded financing commitments to provide a $3.9 billion acquisition facility. In connection with receipt of proceeds from Dominion’s issuance of common stock, the acquisition facility was reduced from $3.9 billion to $3.14 billion in April 2016. See Note 14 for more information. At June 30, 2016, $500 million of such proceeds are included in restricted cash and cash equivalents in Dominion’s Consolidated Balance Sheets. Dominion intends to permanently finance the transaction in a manner that supports its existing credit ratings targets by issuing a combination of common stock, mandatory convertibles and debt at Dominion, and indirectly through the issuance of securities at Dominion Midstream, the proceeds of which will be applied to pay Dominion for certain assets of Questar, which are, subject to relevant approvals, expected to be contributed to Dominion Midstream.

The transaction requires approval of Questar’s shareholders and clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. In February 2016, the Federal Trade Commission granted antitrust approval of the Questar Combination under the Hart-Scott-Rodino Act. In March 2016, Questar and Dominion filed for review and approval, as required, from the Utah Public Service Commission and the Wyoming Public Service Commission, and provided information regarding the transaction to the Idaho Public Utilities Commission. In May 2016, Questar’s shareholders voted to approve the Questar Combination. The Questar Combination contains certain termination rights for both Dominion and Questar, and provides that, upon termination of the Questar Combination under specified circumstances, Dominion would be required to pay a termination fee of $154 million to Questar and Questar would be required to pay Dominion a termination fee of $99 million. Subject to any remaining required regulatory approvals and meeting closing conditions, Dominion targets closing by the end 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 $64 million of consideration, consisting of $2 million in cash and a $62 million payable. As of June 30, 2016, an $11 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Four Brothers’ purpose is to develop and operate four solar projects located in Utah, which will produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $730 million to construct, including the initial acquisition cost. Dominion is obligated to contribute $445 million of capital to fund the construction of the projects and has contributed $370 million through June 30, 2016. The facilities are expected to begin commercial operations by the end of the third quarter of 2016, with generating capacity of approximately 320 MW.

In September 2015, Dominion acquired 50% of the units in Three Cedars from SunEdison for $43 million of consideration, consisting of $6 million in cash and a $37 million payable. As of June 30, 2016, a $7 million payable is included in other current liabilities in Dominion’s Consolidated Balance Sheets. Three Cedars’ purpose is to develop and operate three solar projects located in Utah, which will produce and sell electricity and renewable energy credits. The projects are expected to cost approximately $425 million to construct. Dominion is obligated to contribute $276 million of capital to fund the construction of the projects and has contributed $223 million through June 30, 2016. The facilities are expected to begin commercial operations by the end of the third quarter of 2016, with generating capacity of 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 $89 million of property, plant and equipment and $25 million of noncontrolling interest. The allocation of the $43 million purchase price for Three Cedars resulted in $65 million of property, plant and equipment and $22 million of noncontrolling interest. The noncontrolling interest for each entity was measured at fair value using the discounted cash flow method, with the primary components of the valuation being future cash flows (both incoming and outgoing) and the discount rate. Dominion determined its discount rate based on the cost of capital a utility-scale investor would expect, as well as the cost of capital an individual project developer could achieve via a combination of non-recourse project financing and outside equity partners. The acquired assets of Four Brothers and Three Cedars are included in the Dominion Generation operating segment.

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

23

In April 2016, SunEdison filed for Chapter 11 bankruptcy; however, this is not expected to have a material adverse effect on Dominion, Four Brothers or Three Cedars.

Wholly-Owned Merchant Solar Projects

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

Completed Acquisition Date	Seller	Number of Projects	Project Location	Project Name(s)	Initial Acquisition Cost (millions)(1)		Project Cost (millions)(2)		Date of Commercial Operations	MW Capacity
April 2015	EC&R NA Solar PV, LLC	1	California	Alamo	$	66	$	66	May 2015		20
April 2015	EDF Renewable Development, Inc.	3	California	Cottonwood(3)		106		106	May 2015		24
June 2015	EDF Renewable Development, Inc.	1	California	Catalina 2		68		68	July 2015		18

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

(2) Includes acquisition cost.

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

Sale of Interest in Merchant Solar Projects

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

Acquisition of DCG

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

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

Dominion Gas

Assignments of Shale Development Rights

In December 2013, Dominion Gas closed an agreement with a natural gas producer to convey over time approximately 79,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provided for payments to Dominion Gas, subject to customary adjustments, of up to approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In March 2015, Dominion Gas and the natural gas

24

producer closed on an amendment to the agreement, which included the immediate conveyance of approximately 9,000 acres of Marcellus Shale development rights and a two year extension of the term of the original agreement. The conveyance of development rights resulted in the recognition of $43 million ($27 million after-tax) of previously deferred revenue to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income. In April 2016, Dominion Gas and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of a 32% partial interest in the remaining approximately 70,000 acres. This conveyance resulted in the recognition of the remaining $35 million ($21 million after-tax) of previously deferred revenue to operations and maintenance expense in Dominion Gas’ Consolidated Statements of Income.

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

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

Note 4. Operating Revenue

The Companies’ operating revenue consists of the following:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
(millions)
Dominion
Electric sales:
Regulated	$	1,718	$	1,779	$	3,560	$	3,891
Nonregulated		335		351		724		757
Gas sales:
Regulated		26		31		91		147
Nonregulated		54		87		172		295
Gas transportation and storage		369		385		784		856
Other		96		114		188		210
Total operating revenue	$	2,598	$	2,747	$	5,519	$	6,156
Virginia Power
Regulated electric sales	$	1,718	$	1,779	$	3,560	$	3,891
Other		58		34		106		59
Total operating revenue	$	1,776	$	1,813	$	3,666	$	3,950
Dominion Gas
Gas sales:
Regulated	$	12	$	21	$	41	$	78
Nonregulated		6		1		7		4
Gas transportation and storage		301		321		652		733
NGL revenue		9		22		26		51
Other		40		30		73		60
Total operating revenue	$	368	$	395	$	799	$	926

25

Note 5. Income Taxes

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

	Dominion						Virginia Power						Dominion Gas
Six Months Ended June 30,	2016			2015			2016			2015			2016			2015
United States statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		4.3			3.3			4.0			3.8			3.8			3.9
Investment tax credits		(9.9	)		(2.7	)		—			—			—			—
Production tax credits		(0.8	)		(0.8	)		(0.6	)		(0.5	)		—			—
State legislative change		(1.3	)		—			—			—			—			—
Other, net		(2.3	)		(1.0	)		(0.5	)		(0.7	)		(0.1	)		—
Effective tax rate		25.0	%		33.8	%		37.9	%		37.6	%		38.7	%		38.9	%

As of June 30, 2016, there have been no material changes in the Companies’ unrecognized tax benefits or possible changes that could reasonably be expected to occur during the next twelve months. See Note 5 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015 for a discussion of these unrecognized tax benefits.

Note 6. Earnings Per Share

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
(millions, except EPS)
Net income attributable to Dominion	$	452	$	413	$	976	$	949
Average shares of common stock outstanding – Basic		615.6		591.5		606.1		589.7
Net effect of dilutive securities(1)		1.4		1.0		1.5		1.5
Average shares of common stock outstanding – Diluted		617.0		592.5		607.6		591.2
Earnings Per Common Share – Basic	$	0.73	$	0.70	$	1.61	$	1.61
Earnings Per Common Share – Diluted	$	0.73	$	0.70	$	1.61	$	1.60

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

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

26

Note 7. Accumulated Other Comprehensive Income

Dominion

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

	Deferred Gains and Losses on Derivatives- Hedging Activities			Unrealized Gains and Losses on Investment Securities			Unrecognized Pension and Other Postretirement Benefit Costs			Other Comprehensive Income (Loss) From Equity Method Investee			Total
(millions)
Three Months Ended June 30, 2016
Beginning balance	$	(186	)	$	517		$	(789	)	$	(5	)	$	(463	)
Other comprehensive income before reclassifications: gains (losses)		(11	)		26			—			(1	)		14
Amounts reclassified from AOCI(1): (gains) losses		(44	)		(8	)		8			—			(44	)
Net current-period other comprehensive income (loss)		(55	)		18			8			(1	)		(30	)
Ending balance	$	(241	)	$	535		$	(781	)	$	(6	)	$	(493	)
Three Months Ended June 30, 2015
Beginning balance	$	(177	)	$	542		$	(769	)	$	(5	)	$	(409	)
Other comprehensive income before reclassifications: gains (losses)		92			(11	)		3			—			84
Amounts reclassified from AOCI(1): (gains) losses		(61	)		(12	)		12			—			(61	)
Net current-period other comprehensive income (loss)		31			(23	)		15			—			23
Ending balance	$	(146	)	$	519		$	(754	)	$	(5	)	$	(386	)
Six Months Ended June 30, 2016
Beginning balance	$	(176	)	$	504		$	(797	)	$	(5	)	$	(474	)
Other comprehensive income before reclassifications: gains (losses)		42			41			—			(1	)		82
Amounts reclassified from AOCI(1): (gains) losses		(107	)		(10	)		16			—			(101	)
Net current-period other comprehensive income (loss)		(65	)		31			16			(1	)		(19	)
Ending balance	$	(241	)	$	535		$	(781	)	$	(6	)	$	(493	)
Six Months Ended June 30, 2015
Beginning balance	$	(178	)	$	548		$	(782	)	$	(4	)	$	(416	)
Other comprehensive income before reclassifications: gains (losses)		34			4			3			(1	)		40
Amounts reclassified from AOCI(1): (gains) losses		(2	)		(33	)		25			—			(10	)
Net current-period other comprehensive income (loss)		32			(29	)		28			(1	)		30
Ending balance	$	(146	)	$	519		$	(754	)	$	(5	)	$	(386	)

(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 June 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(87	)	Operating revenue
		2		Purchased gas
		3		Electric fuel and other energy-related purchases
Interest rate contracts		8		Interest and related charges
Foreign currency contracts		2		Other income
		(72	)
Tax		28		Income tax expense
	$	(44	)

27

Details About AOCI Components	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(20	)	Other income
Impairment		7		Other income
		(13	)
Tax		5		Income tax expense
	$	(8	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(3	)	Other operations and maintenance
Actuarial (gains) losses		17		Other operations and maintenance
		14
Tax		(6	)	Income tax expense
	$	8
Three Months Ended June 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(107	)	Operating revenue
		2		Purchased gas
Interest rate contracts		3		Interest and related charges
		(102	)
Tax		41		Income tax expense
	$	(61	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(25	)	Other income
Impairment		5		Other income
		(20	)
Tax		8		Income tax expense
	$	(12	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(3	)	Other operations and maintenance
Actuarial (gains) losses		24		Other operations and maintenance
		21
Tax		(9	)	Income tax expense
	$	12
Six Months Ended June 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(201	)	Operating revenue
		8		Purchased gas
		6		Electric fuel and other energy-related purchases
Interest rate contracts		11		Interest and related charges
Foreign currency contracts		2		Other income
		(174	)
Tax		67		Income tax expense
	$	(107	)

28

Details About AOCI Components	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(30	)	Other income
Impairment		14		Other income
		(16	)
Tax		6		Income tax expense
	$	(10	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(7	)	Other operations and maintenance
Actuarial (gains) losses		35		Other operations and maintenance
		28
Tax		(12	)	Income tax expense
	$	16
Six Months Ended June 30, 2015
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(15	)	Operating revenue
		7		Purchased gas
		(1	)	Electric fuel and other energy-related purchases
Interest rate contracts		5		Interest and related charges
		(4	)
Tax		2		Income tax expense
	$	(2	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(64	)	Other income
Impairment		11		Other income
		(53	)
Tax		20		Income tax expense
	$	(33	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(6	)	Other operations and maintenance
Actuarial (gains) losses		49		Other operations and maintenance
		43
Tax		(18	)	Income tax expense
	$	25

29

Dominion Gas

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

	Deferred Gains and Losses on Derivatives- Hedging Activities			Unrecognized Pension and Other Postretirement Benefit Costs			Total
(millions)
Three Months Ended June 30, 2016
Beginning balance	$	(25	)	$	(82	)	$	(107	)
Other comprehensive income before reclassifications: losses		(9	)		—			(9	)
Amounts reclassified from AOCI(1): losses		—			1			1
Net current-period other comprehensive income (loss)		(9	)		1			(8	)
Ending balance	$	(34	)	$	(81	)	$	(115	)
Three Months Ended June 30, 2015
Beginning balance	$	(24	)	$	(65	)	$	(89	)
Other comprehensive income before reclassifications: gains		3			—			3
Amounts reclassified from AOCI(1): (gains) losses		(1	)		1			—
Net current-period other comprehensive income		2			1			3
Ending balance	$	(22	)	$	(64	)	$	(86	)
Six Months Ended June 30, 2016
Beginning balance	$	(17	)	$	(82	)	$	(99	)
Other comprehensive income before reclassifications: losses		(15	)		—			(15	)
Amounts reclassified from AOCI(1): (gains) losses		(2	)		1			(1	)
Net current-period other comprehensive income (loss)		(17	)		1			(16	)
Ending balance	$	(34	)	$	(81	)	$	(115	)
Six Months Ended June 30, 2015
Beginning balance	$	(20	)	$	(66	)	$	(86	)
Other comprehensive income before reclassifications: losses		(1	)		—			(1	)
Amounts reclassified from AOCI(1): (gains) losses		(1	)		2			1
Net current-period other comprehensive income (loss)		(2	)		2			—
Ending balance	$	(22	)	$	(64	)	$	(86	)

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

30

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

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

31

Note 8. Fair Value Measurements

The Companies’ fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015. See Note 9 in this report for further information about the Companies’ derivatives and hedge accounting activities.

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

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

• Foreign currency forward exchange rates

• Credit quality of counterparties and the Companies

• Notional value

• Credit enhancements

• Time value

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

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

	Fair Value (millions)		Valuation Techniques	Unobservable Input	Range			Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)	$	123	Discounted cash flow	Market price (per Dth)(3)		(2) - 7			—
				Credit spread(4)		1% - 6	%		3	%
FTRs		6	Discounted cash flow	Market price (per MWh)(3)		(8) - 3			1
Physical and financial options:
Natural gas		8	Option model	Market price (per Dth)(3)		2 - 7			4
				Price volatility(5)		20% - 42	%		25	%
Total assets	$	137
Liabilities
Physical and financial forwards and futures:
Natural gas(2)	$	5	Discounted cash flow	Market price (per Dth)(3)		(1) - 4			3
FTRs		7	Discounted cash flow	Market price (per MWh)(3)		(2) - 5			1
Physical and financial options:
Natural gas		1	Option model	Market price (per Dth)(3)		2 - 4			3
				Price volatility(5)		29% - 42	%		36	%
Total liabilities	$	13

32

(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)
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 June 30, 2016
Assets
Derivatives:
Commodity	$	—	$	192	$	137	$	329
Interest rate		—		25		—		25
Investments(1):
Equity securities:
United States:
Large cap		2,617		—		—		2,617
Other		5		—		—		5
REIT		72		—		—		72
Non-United States:
Large cap		10		—		—		10
Fixed income:
Corporate debt instruments		—		498		—		498
United States Treasury securities and agency debentures		462		236		—		698
State and municipal		—		364		—		364
Other		—		112		—		112
Cash equivalents and other		5		—		—		5
Total assets	$	3,171	$	1,427	$	137	$	4,735
Liabilities
Derivatives:
Commodity	$	—	$	87	$	13	$	100
Interest rate		—		366		—		366
Foreign currency		—		7		—		7
Total liabilities	$	—	$	460	$	13	$	473

33

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

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

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

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

The following table presents Dominion’s classification of gains and losses included in earnings in the Level 3 fair value category. There were no unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three months ended June 30, 2016 and 2015.

34

	Operating Revenue		Electric Fuel and Other Energy- Related Purchases			Total
(millions)
Three Months Ended June 30, 2016
Total gains (losses) included in earnings	$	—	$	(10	)	$	(10	)
Three Months Ended June 30, 2015
Total gains (losses) included in earnings	$	—	$	(5	)	$	(5	)
Six Months Ended June 30, 2016
Total gains (losses) included in earnings	$	—	$	(17	)	$	(17	)
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		—		—			—
Six Months Ended June 30, 2015
Total gains (losses) included in earnings	$	2	$	8		$	10
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date		1		(1	)		—

Virginia Power

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

	Fair Value (millions)		Valuation Techniques	Unobservable Input	Range			Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)	$	121	Discounted cash flow	Market price (per Dth)(3)		(2) - 7			—
				Credit spread(4)		1% - 6	%		3	%
FTRs		6	Discounted cash flow	Market price (per MWh)(3)		(8) - 3			1
Physical and financial options:
Natural gas		5	Option model	Market price (per Dth)(3)		2 - 7			4
				Price volatility(5)		20% - 33	%		24	%
Total assets	$	132
Liabilities
Physical and financial forwards and futures:
FTRs	$	7	Discounted cash flow	Market price (per MWh)(3)		(2) - 5			1
Total liabilities	$	7

(1) Averages weighted by volume.

(2) Includes basis.

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

(4) Represents credit spreads unrepresented in published markets.

(5) Represents volatilities unrepresented in published markets.

35

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

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

36

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

	Level 1		Level 2		Level 3		Total
(millions)
At June 30, 2016
Assets
Derivatives:
Commodity	$	—	$	31	$	132	$	163
Investments(1):
Equity securities:
United States large cap		1,137		—		—		1,137
REIT		72		—		—		72
Fixed income:
Corporate debt instruments		—		283		—		283
United States Treasury securities and agency debentures		166		111		—		277
State and municipal		—		159		—		159
Other		—		48		—		48
Total assets	$	1,375	$	632	$	132	$	2,139
Liabilities
Derivatives:
Commodity	$	—	$	10	$	7	$	17
Interest rate		—		257		—		257
Total liabilities	$	—	$	267	$	7	$	274
At December 31, 2015
Assets
Derivatives:
Commodity	$	—	$	13	$	101	$	114
Interest rate		—		13		—		13
Investments(1):
Equity securities:
United States large cap		1,100		—		—		1,100
REIT		63		—		—		63
Fixed income:
Corporate debt instruments		—		238		—		238
United States Treasury securities and agency debentures		180		79		—		259
State and municipal		—		175		—		175
Other		—		34		—		34
Total assets	$	1,343	$	552	$	101	$	1,996
Liabilities
Derivatives:
Commodity	$	—	$	19	$	8	$	27
Interest rate		—		59		—		59
Total liabilities	$	—	$	78	$	8	$	86

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

37

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
(millions)
Beginning balance	$	110		$	78		$	93		$	102
Total realized and unrealized gains (losses):
Included in earnings		(9	)		(5	)		(17	)		8
Included in regulatory assets/liabilities		15			(5	)		32			(29	)
Settlements		9			5			17			(8	)
Ending balance	$	125		$	73		$	125		$	73

The gains and losses included in earnings in the Level 3 fair value category were classified in electric fuel and other energy-related purchases in Virginia Power’s Consolidated Statements of Income for the three and six months ended June 30, 2016 and 2015. There were no unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and six months ended June 30, 2016 and 2015.

Dominion Gas

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

	Level 1		Level 2		Level 3		Total
(millions)
At June 30, 2016
Assets
Commodity	$	—	$	3	$	—	$	3
Total Assets	$	—	$	3	$	—	$	3
Liabilities
Commodity	$	—	$	5	$	—	$	5
Foreign currency		—		7		—		7
Total liabilities	$	—	$	12	$	—	$	12
At December 31, 2015
Assets
Commodity	$	—	$	5	$	6	$	11
Total Assets	$	—	$	5	$	6	$	11
Liabilities
Interest rate	$	—	$	14	$	—	$	14
Total liabilities	$	—	$	14	$	—	$	14

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2016		2015			2016			2015
(millions)
Beginning balance	$	—	$	—		$	6		$	2
Total realized and unrealized gains (losses):
Included in earnings		—		(1	)		—			1
Included in other comprehensive income (loss)		—		—			2			(12	)
Settlements		—		—			—			(1	)
Transfers out of Level 3		—		—			(8	)		9
Ending balance	$	—	$	(1	)	$	—		$	(1	)

38

The gains and losses included in earnings in the Level 3 fair value category were classified in operating revenue in Dominion Gas’ Consolidated Statements of Income for the three and six months ended June 30, 2015. There were no unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and six months ended June 30, 2016 and 2015.

Fair Value of Financial Instruments

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

	June 30, 2016				December 31, 2015
	Carrying     Amount		Estimated Fair     Value(1)		Carrying     Amount		Estimated Fair     Value(1)
(millions)
Dominion
Long-term debt, including securities due within one year(2)	$	22,754	$	25,400	$	21,873	$	23,210
Junior subordinated notes(3)		2,399		2,310		1,340		1,192
Remarketable subordinated notes(3)		982		1,037		2,080		2,129
Virginia Power
Long-term debt, including securities due within one year(3)	$	9,661	$	11,329	$	9,368	$	10,400
Dominion Gas
Long-term debt, including securities due within one year(4)	$	3,941	$	4,116	$	3,269	$	3,299

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

(2) Carrying amount includes amounts which represent the unamortized debt issuance costs, discount and/or premium, and foreign currency remeasurement adjustments. At June 30, 2016 and December 31, 2015, includes the valuation of certain fair value hedges associated with fixed rate debt of $21 million and $7 million, respectively.

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

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

Note 9. Derivatives and Hedge Accounting Activities

The Companies’ accounting policies, objectives and strategies for using derivative instruments are discussed in Note 2 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015. See Note 8 in this report for further information about fair value measurements and associated valuation methods for derivatives.

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

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

39

Dominion

Balance Sheet Presentation

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

	June 30, 2016						December 31, 2015
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	231	$	—	$	231	$	217	$	—	$	217
Exchange		91		—		91		138		—		138
Interest rate contracts:
Over-the-counter		25		—		25		24		—		24
Total derivatives, subject to a master netting or similar arrangement		347		—		347		379		—		379
Total derivatives, not subject to a master netting or similar arrangement		7		—		7		9		—		9
Total	$	354	$	—	$	354	$	388	$	—	$	388

			June 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	231	$	16	$	—	$	215	$	217	$	37	$	—	$	180
Exchange		91		63		—		28		138		82		—		56
Interest rate contracts:
Over-the-counter		25		15		—		10		24		22		—		2
Total	$	347	$	94	$	—	$	253	$	379	$	141	$	—	$	238

40

	June 30, 2016						December 31, 2015
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	32	$	—	$	32	$	70	$	—	$	70
Exchange		63		—		63		82		—		82
Interest rate contracts:
Over-the-counter		366		—		366		183		—		183
Foreign currency contracts:
Over-the-counter		7		—		7		—		—		—
Total derivatives, subject to a master netting or similar arrangement		468		—		468		335		—		335
Total derivatives, not subject to a master netting or similar arrangement		5		—		5		8		—		8
Total	$	473	$	—	$	473	$	343	$	—	$	343

			June 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	32	$	16	$	1	$	15	$	70	$	37	$	—	$	33
Exchange		63		63		—		—		82		82		—		—
Interest rate contracts:
Over-the-counter		366		15		—		351		183		22		—		161
Foreign currency contracts:
Over-the-counter		7		—		—		7		—		—		—		—
Total	$	468	$	94	$	1	$	373	$	335	$	141	$	—	$	194

Volumes

The following table presents the volume of Dominion’s derivative activity at June 30, 2016. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

41

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)		125		38
Basis		190		580
Electricity (MWh):
Fixed price		11,749,639		1,978,640
FTRs		99,882,813		—
Liquids (Gal)(2)		59,807,554		—
Interest rate(3)	$	2,400,000,000	$	2,100,000,000
Foreign currency(3)(4)	$	—	$	280,000,000

(1) Includes options.

(2) Includes NGLs and oil.

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

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

Ineffectiveness and AOCI

For the three and six months ended June 30, 2016 and 2015, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

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

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	10		$	9			22 months
Electricity		65			65			18 months
Other		(1	)		(1	)		9 months
Interest rate		(312	)		(23	)		381 months
Foreign currency		(3	)		(3	)		120 months
Total	$	(241	)	$	47

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

42

Fair Value and Gains and Losses on Derivative Instruments

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

	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At June 30, 2016
ASSETS
Current Assets
Commodity	$	67	$	121	$	188
Interest rate		4		—		4
Total current derivative assets(1)		71		121		192
Noncurrent Assets
Commodity		6		135		141
Interest rate		21		—		21
Total noncurrent derivative assets(2)		27		135		162
Total derivative assets	$	98	$	256	$	354
LIABILITIES
Current Liabilities
Commodity	$	27	$	61	$	88
Interest rate		178		—		178
Foreign currency		5		—		5
Total current derivative liabilities(3)		210		61		271
Noncurrent Liabilities
Commodity		5		7		12
Interest rate		188		—		188
Foreign currency		2		—		2
Total noncurrent derivative liabilities(4)		195		7		202
Total derivative liabilities	$	405	$	68	$	473
At December 31, 2015
ASSETS
Current Assets
Commodity	$	101	$	151	$	252
Interest rate		3		—		3
Total current derivative assets(1)		104		151		255
Noncurrent Assets
Commodity		3		109		112
Interest rate		21		—		21
Total noncurrent derivative assets(2)		24		109		133
Total derivative assets	$	128	$	260	$	388
LIABILITIES
Current Liabilities
Commodity	$	32	$	116	$	148
Interest rate		164		—		164
Total current derivative liabilities(3)		196		116		312
Noncurrent Liabilities
Commodity		—		12		12
Interest rate		19		—		19
Total noncurrent derivative liabilities(4)		19		12		31
Total derivative liabilities	$	215	$	128	$	343

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

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

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

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

43

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended June 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	87
Purchased gas					(2	)
Electric fuel and other energy-related purchases					(3	)
Total commodity	$	12		$	82		$	—
Interest rate(3)		(23	)		(8	)		(108	)
Foreign currency(4)		(7	)		(2	)		—
Total	$	(18	)	$	72		$	(108	)
Three Months Ended June 30, 2015
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	107
Purchased gas					(2	)
Total commodity	$	94		$	105		$	—
Interest rate(3)		57			(3	)		(91	)
Total	$	151		$	102		$	(91	)
Six Months Ended June 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	201
Purchased gas					(8	)
Electric fuel and other energy-related purchases					(6	)
Total commodity	$	185		$	187		$	—
Interest rate(3)		(110	)		(11	)		(241	)
Foreign currency(4)		(7	)		(2	)		—
Total	$	68		$	174		$	(241	)
Six Months Ended June 30, 2015
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	15
Purchased gas					(7	)
Electric fuel and other energy-related purchases					1
Total commodity	$	54		$	9		$	3
Interest rate(3)		(1	)		(5	)		42
Total	$	53		$	4		$	45

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

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

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

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

44

	Amount of Gain (Loss) Recognized in Income on  Derivatives(1)
	Three Months Ended June 30,						Six Months Ended June 30,
Derivatives Not Designated as Hedging Instruments	2016			2015			2016			2015
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue	$	(8	)	$	15		$	(6	)	$	18
Purchased gas		8			(7	)		7			(9	)
Electric fuel and other energy-related purchases		(9	)		3			(31	)		9
Other operations and maintenance		1			—			—			—
Total	$	(8	)	$	11		$	(30	)	$	18

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

Virginia Power

Balance Sheet Presentation

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

	June 30, 2016						December 31, 2015
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	127	$	—	$	127	$	101	$	—	$	101
Interest rate contracts:
Over-the-counter		—		—		—		13		—		13
Total derivatives, subject to a master netting or similar arrangement		127		—		127		114		—		114
Total derivatives, not subject to a master netting or similar arrangement		36		—		36		13		—		13
Total	$	163	$	—	$	163	$	127	$	—	$	127

			June 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	127	$	7	$	—	$	120	$	101	$	3	$	—	$	98
Interest rate contracts:
Over-the-counter		—		—		—		—		13		10		—		3
Total	$	127	$	7	$	—	$	120	$	114	$	13	$	—	$	101

45

	June 30, 2016						December 31, 2015
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	14	$	—	$	14	$	5	$	—	$	5
Interest rate contracts:
Over-the-counter		257		—		257		59		—		59
Total derivatives, subject to a master netting or similar arrangement		271		—		271		64		—		64
Total derivatives, not subject to a master netting or similar arrangement		3		—		3		22		—		22
Total	$	274	$	—	$	274	$	86	$	—	$	86

			June 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	14	$	7	$	1	$	6	$	5	$	3	$	—	$	2
Interest rate contracts:
Over-the-counter		257		—		—		257		59		10		—		49
Total	$	271	$	7	$	1	$	263	$	64	$	13	$	—	$	51

Volumes

The following table presents the volume of Virginia Power’s derivative activity at June 30, 2016. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)		42		16
Basis		67		538
Electricity (MWh):
FTRs		97,710,646		—
Interest rate	$	700,000,000	$	1,100,000,000

(1) Includes options.

Ineffectiveness and AOCI

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

46

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

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

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

47

Fair Value and Gains and Losses on Derivative Instruments

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

	Fair Value – Derivatives under Hedge Accounting		Fair Value –Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At June 30, 2016
ASSETS
Current Assets
Commodity	$	—	$	34	$	34
Total current derivative assets(1)		—		34		34
Noncurrent Assets
Commodity		—		129		129
Total noncurrent derivative assets(2)		—		129		129
Total derivative assets	$	—	$	163	$	163
LIABILITIES
Current Liabilities
Commodity	$	—	$	12	$	12
Interest rate		69		—		69
Total current derivative liabilities(3)		69		12		81
Noncurrent Liabilities
Commodity		—		5		5
Interest rate		188		—		188
Total noncurrent derivatives liabilities (4)		188		5		193
Total derivative liabilities	$	257	$	17	$	274
At December 31, 2015
ASSETS
Current Assets
Commodity	$	—	$	18	$	18
Total current derivative assets(1)		—		18		18
Noncurrent Assets
Commodity		—		96		96
Interest rate		13		—		13
Total noncurrent derivative assets(2)		13		96		109
Total derivative assets	$	13	$	114	$	127
LIABILITIES
Current Liabilities
Commodity	$	—	$	23	$	23
Interest rate		57		—		57
Total current derivative liabilities(3)		57		23		80
Noncurrent Liabilities
Commodity		—		4		4
Interest rate		2		—		2
Total noncurrent derivative liabilities(4)		2		4		6
Total derivative liabilities	$	59	$	27	$	86

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

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

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

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

48

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase(Decrease) in Derivatives Subject to Regulatory Treatment(2)
(millions)
Three Months Ended June 30, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(10	)	$	—		$	(108	)
Total	$	(10	)	$	—		$	(108	)
Three Months Ended June 30, 2015
Derivative type and location of gains (losses):
Interest rate(3)	$	11		$	—		$	91
Total	$	11		$	—		$	91
Six Months Ended June 30, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(24	)	$	(1	)	$	(241	)
Total	$	(24	)	$	(1	)	$	(241	)
Six Months Ended June 30, 2015
Derivative type and location of gains (losses):
Commodity:
Electric fuel and other energy-related purchases				$	(1	)
Total commodity	$	—		$	(1	)	$	3
Interest rate(3)		5			—			42
Total	$	5		$	(1	)	$	45

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

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

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

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

(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.

49

Dominion Gas

Balance Sheet Presentation

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

	June 30, 2016						December 31, 2015
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	3	$	—	$	3	$	11	$	—	$	11
Total derivatives, subject to a master netting or similar arrangement	$	3	$	—	$	3	$	11	$	—	$	11

			June 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	3	$	3	$	—	$	—	$	11	$	—	$	—	$	11
Total	$	3	$	3	$	—	$	—	$	11	$	—	$	—	$	11

	June 30, 2016						December 31, 2015
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	5	$	—	$	5	$	—	$	—	$	—
Interest rate contracts:
Over-the-counter		—		—		—		14		—		14
Foreign currency contracts:
Over-the-counter		7		—		7		—		—		—
Total derivatives, subject to a master netting or similar arrangement	$	12	$	—	$	12	$	14	$	—	$	14

50

			June 30, 2016								December 31, 2015
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts
Over-the-counter	$	5	$	3	$	—	$	2	$	—	$	—	$	—	$	—
Interest rate contracts:
Over-the-counter		—		—		—		—		14		—		—		14
Foreign currency contracts:
Over-the-counter		7		—		—		7		—		—		—		—
Total	$	12	$	3	$	—	$	9	$	14	$	—	$	—	$	14

Volumes

The following table presents the volume of Dominion Gas’ derivative activity at June 30, 2016. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.

	Current		Noncurrent
Natural Gas (bcf):
Fixed price		7		—
Basis		7		—
NGLs (Gal)		52,247,554		—
Foreign currency(1)	$	—	$	280,000,000

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

Ineffectiveness and AOCI

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

The following table presents selected information related to losses on cash flow hedges included in AOCI in Dominion Gas’ Consolidated Balance Sheet at June 30, 2016:

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
NGLs	$	(1	)	$	(1	)		9 months
Interest rate		(30	)		(4	)		342 months
Foreign currency		(3	)		(3	)		120 months
Total	$	(34	)	$	(8	)

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

51

Fair Value and Gains and Losses on Derivative Instruments

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

	Fair Value-Derivatives Under Hedge Accounting		Fair Value-Derivatives Not Under Hedge Accounting		Total Fair Value
(millions)
At June 30, 2016
ASSETS
Current Assets
Commodity	$	2	$	1	$	3
Total current derivative assets(1)		2		1		3
Total derivative assets	$	2	$	1	$	3
LIABILITIES
Current Liabilities
Commodity	$	4	$	1	$	5
Foreign currency		5		—		5
Total current derivative liabilities(3)		9		1		10
Noncurrent Liabilities
Foreign currency		2		—		2
Total noncurrent derivative liabilities(4)		2		—		2
Total derivative liabilities	$	11	$	1	$	12
At December 31, 2015
ASSETS
Current Assets
Commodity	$	10	$	—	$	10
Total current derivative assets(1)		10		—		10
Noncurrent Assets
Commodity		1		—		1
Total noncurrent derivatives assets(2)		1		—		1
Total derivative assets	$	11	$	—	$	11
LIABILITIES
Noncurrent Liabilities
Interest rate	$	14	$	—	$	14
Total noncurrent derivative liabilities(4)		14		—		14
Total derivative liabilities	$	14	$	—	$	14

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

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

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

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

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

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)			Amount of Gain (Loss) Reclassified From AOCI to Income
(millions)
Three Months Ended June 30, 2016
Derivative Type and Location of Gains (Losses):
Commodity	$	(6	)	$	—
Foreign currency(3)		(7	)		(2	)
Total	$	(13	)	$	(2	)
Three Months Ended June 30, 2015
Derivative Type and Location of Gains (Losses):
Commodity:
Operating revenue				$	1
Total commodity	$	—		$	1
Interest rate(2)		4			—
Total	$	4		$	1
Six Months Ended June 30, 2016
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	4
Total commodity	$	(7	)	$	4
Interest rate(2)		(9	)		—
Foreign currency(3)		(7	)		(2	)
Total	$	(23	)	$	2
Six Months Ended June 30, 2015
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	1
Total commodity	$	(2	)	$	1
Total	$	(2	)	$	1

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

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

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

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

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Note 10. Investments

Dominion

Equity and Debt Securities

Rabbi Trust Securities

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

Decommissioning Trust Securities

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

	Amortized Cost			Total Unrealized Gains(1)		Total Unrealized Losses(1)			Fair Value
(millions)
At June 30, 2016
Marketable equity securities:
United States large cap	$	1,326		$	1,251	$	—		$	2,577
REIT		61			11		—			72
Marketable debt securities:
Corporate bonds		474			25		(1	)		498
United States Treasury securities and agency debentures		672			26		—			698
State and municipal		290			31		—			321
Other		108			—		—			108
Cost method investments		69			—		—			69
Cash equivalents and other(2)		(12	)		—		—			(12	)
Total	$	2,988		$	1,344	$	(1	)(3)	$	4,331
At December 31, 2015
Marketable equity securities:
United States large cap	$	1,295		$	1,213	$	—		$	2,508
REIT		59			4		—			63
Marketable debt securities:
Corporate bonds		433			11		(7	)		437
United States Treasury securities and agency debentures		654			8		(4	)		658
State and municipal		312			22		—			334
Other		99			—		—			99
Cost method investments		70			—		—			70
Cash equivalents and other(2)		14			—		—			14
Total	$	2,936		$	1,258	$	(11	)(3)	$	4,183

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

(2) Includes pending purchases of securities of $16 million and pending sales of securities of $12 million at June 30, 2016 and December 31, 2015, respectively.

(3) The fair value of securities in an unrealized loss position was $90 million and $592 million at June 30, 2016 and December 31, 2015, respectively.

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

	Amount
(millions)
Due in one year or less	$	212
Due after one year through five years		458
Due after five years through ten years		390
Due after ten years		565
Total	$	1,625

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
(millions)
Proceeds from sales	$	341	$	243	$	709	$	580
Realized gains(1)		37		44		62		100
Realized losses(1)		15		12		34		29

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

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

Virginia Power

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

	Amortized Cost			Total Unrealized Gains(1)		Total Unrealized Losses(1)			Fair Value
(millions)
At June 30, 2016
Marketable equity securities:
United States large cap	$	590		$	546	$	—		$	1,136
REIT		61			11		—			72
Marketable debt securities:
Corporate bonds		271			13		(1	)		283
United States Treasury securities and agency debentures		270			7		—			277
State and municipal		141			17		—			158
Other		48			—		—			48
Cost method investments		69			—		—			69
Cash equivalents and other(2)		(13	)		—		—			(13	)
Total	$	1,437		$	594	$	(1	)(3)	$	2,030
At December 31, 2015
Marketable equity securities:
United States large cap	$	574		$	525	$	—		$	1,099
REIT		59			4		—			63
Marketable debt securities:
Corporate bonds		237			5		(4	)		238
United States Treasury securities and agency debentures		260			1		(2	)		259
State and municipal		162			13		(1	)		174
Other		34			—		—			34
Cost method investments		70			—		—			70
Cash equivalents and other(2)		8			—		—			8
Total	$	1,404		$	548	$	(7	)(3)	$	1,945

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

(2) Includes pending purchases of securities of $13 million and pending sales of securities of $8 million at June 30, 2016 and December 31, 2015, respectively.

(3) The fair value of securities in an unrealized loss position was $66 million and $281 million at June 30, 2016 and December 31, 2015, respectively.

55

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

	Amount
(millions)
Due in one year or less	$	71
Due after one year through five years		207
Due after five years through ten years		218
Due after ten years		270
Total	$	766

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
(millions)
Proceeds from sales	$	154	$	76	$	347	$	209
Realized gains(1)		18		19		30		37
Realized losses(1)		7		4		17		15

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

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

Equity Method Investments

Dominion Gas

Iroquois

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

Note 11. Regulatory Assets and Liabilities

Regulatory assets and liabilities include the following:

	June 30, 2016		December 31, 2015
(millions)
Dominion
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	95	$	90
Deferred nuclear refueling outage costs(2)		61		75
Deferred cost of fuel used in electric generation(3)		5		111
Other		60		75
Regulatory assets-current(4)		221		351
Unrecognized pension and other postretirement benefit costs(5)		992		1,015
Derivatives(6)		351		110
Deferred rate adjustment clause costs(1)		342		295
PJM transmission rates(7)		192		192
Income taxes recoverable through future rates(8)		137		126

56

	June 30, 2016		December 31, 2015
(millions)
Other		136		127
Regulatory assets-non-current		2,150		1,865
Total regulatory assets	$	2,371	$	2,216
Regulatory liabilities:
Deferred cost of fuel used in electric generation(3)	$	89	$	—
PIPP(9)		25		46
Other		47		54
Regulatory liabilities-current(10)		161		100
Provision for future cost of removal and AROs(11)		1,148		1,120
Nuclear decommissioning trust(12)		852		804
Derivatives(6)		108		79
Deferred cost of fuel used in electric generation(3)		26		97
Other		184		185
Regulatory liabilities-non-current		2,318		2,285
Total regulatory liabilities	$	2,479	$	2,385
Virginia Power
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	72	$	80
Deferred nuclear refueling outage costs(2)		61		75
Deferred cost of fuel used in electric generation(3)		5		111
Other		55		60
Regulatory assets-current		193		326
Derivatives(6)		351		110
Deferred rate adjustment clause costs(1)		254		213
PJM transmission rates(7)		192		192
Income taxes recoverable through future rates(8)		106		97
Other		63		55
Regulatory assets-non-current		966		667
Total regulatory assets	$	1,159	$	993
Regulatory liabilities:
Deferred cost of fuel used in electric generation(3)	$	89	$	—
Other		23		35
Regulatory liabilities-current(10)		112		35
Provision for future cost of removal(11)		913		890
Nuclear decommissioning trust(12)		852		804
Derivatives(6)		108		79
Deferred cost of fuel used in electric generation(3)		26		97
Other		57		59
Regulatory liabilities-non-current		1,956		1,929
Total regulatory liabilities	$	2,068	$	1,964
Dominion Gas
Regulatory assets:
Deferred rate adjustment clause costs(1)	$	23	$	10
Other		2		13
Regulatory assets-current(4)		25		23
Unrecognized pension and other postretirement benefit costs(5)		277		282
Deferred rate adjustment clause costs(1)		88		82

57

	June 30, 2016		December 31, 2015
(millions)
Income taxes recoverable through future rates(8)		20		20
Other		66		65
Regulatory assets-non-current(13)		451		449
Total regulatory assets	$	476	$	472
Regulatory liabilities:
PIPP(9)	$	25	$	46
Other		18		9
Regulatory liabilities-current(10)		43		55
Provision for future cost of removal and AROs(11)		174		170
Other		39		31
Regulatory liabilities-non-current(14)		213		201
Total regulatory liabilities	$	256	$	256

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

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

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

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

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

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

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

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

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

(10) Current regulatory liabilities are presented in other current liabilities in the 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 June 30, 2016, $293 million of Dominion’s, $272 million of Virginia Power’s and $18 million of Dominion Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. These expenditures are expected to be recovered within the next two years.

Note 12. Regulatory Matters

Regulatory Matters Involving Potential Loss Contingencies

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

58

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

FERC - Electric

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

Rates

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

In March 2010, Old Dominion Electric Cooperative and North Carolina Electric Membership Corporation filed a complaint with FERC against Virginia Power claiming, among other issues, that the incremental costs of undergrounding certain transmission line projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. A settlement of the other issues raised in the complaint was approved by FERC in May 2012.

In March 2014, FERC issued an order excluding from Virginia Power’s transmission rates for wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable for non-Virginia wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities because the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to benefit the citizens of Virginia. The order is retroactively effective as of March 2010 and will cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC determined that there was not sufficient evidence on the record to determine the magnitude of the underground increment and held a hearing to determine the appropriate amount of undergrounding cost to be allocated to each wholesale transmission customer in Virginia. While Virginia Power cannot predict the outcome of the hearing, it is not expected to have a material effect on results of operations.

PJM Transmission Rates

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

In August 2009, the court issued its decision affirming the FERC order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above for further consideration by FERC. On remand, FERC reaffirmed its earlier decision to allocate the costs of new facilities 500 kV and above according to the customer’s share of the region’s load. A number of parties filed appeals of the order to the United States Court of Appeals for the Seventh Circuit. In June 2014, the court again remanded the cost allocation issue to FERC. In December 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the cost allocation issue. The hearing only concerns the costs of new facilities approved by PJM prior to February 1, 2013. Transmission facilities approved after February 1, 2013 are allocated on a hybrid cost allocation method approved by FERC and not subject to any court review.

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

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

Other Regulatory Matters

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

Regulation Act Legislation

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

2015 Biennial Review

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

Virginia Fuel Expenses

In May 2016, the Virginia Commission ordered Virginia Power’s proposed fuel rate decrease to become effective July 1, 2016 on an interim basis. Virginia Power’s proposed fuel rate represents a fuel revenue decrease of $286 million when applied to projected kilowatt-hour sales for the period July 1, 2016 to June 30, 2017. This case is pending.

Solar Facility Projects

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

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

Rate Adjustment Clauses

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

• The Virginia Commission previously approved Rider S in conjunction with the Virginia City Hybrid Energy Center. In June 2016, Virginia Power proposed a $254 million revenue requirement for the rate year beginning April 1, 2017, which represents a $3 million increase over the previous year. This matter is pending.

• The Virginia Commission previously approved Rider R in conjunction with Bear Garden. In June 2016, Virginia Power proposed a $75 million revenue requirement for the rate year beginning April 1, 2017, which represents a $1 million increase over the previous year. This matter is pending.

• The Virginia Commission previously approved Rider W in conjunction with Warren County. In June 2016, Virginia Power proposed a $126 million revenue requirement for the rate year beginning April 1, 2017, which represents a $9 million increase over the previous year. This matter is pending.

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• The Virginia Commission previously approved Rider B in conjunction with the conversion of three power stations to biomass. In June 2016, Virginia Power proposed a $28 million revenue requirement for the rate year beginning April 1, 2017, which represents a $1 million decrease over the previous year. This matter is pending.

• The Virginia Commission previously approved Rider GV in conjunction with Greensville County. In June 2016, Virginia Power proposed a $89 million revenue requirement for the rate year beginning April 1, 2017, which represents a $49 million increase over the previous year. This matter is pending.

• The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In June 2016, the Virginia Commission approved a $119 million revenue requirement for the rate year beginning September 1, 2016. It also established a 10.6% ROE for Rider BW effective September 1, 2016.

• The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2016, Virginia Power proposed a $639 million total revenue requirement for the rate year beginning September 1, 2016, which represents a $1 million increase over the revenues projected to be produced during the rate year under current rates. In July 2016, the Virginia Commission approved Virginia Power’s proposed total revenue requirement.

North Anna

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

The motions and petitions filed by BREDL prior to April 2015 were 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 challenging the NRC’s reliance on its rule generically assessing the environmental impacts of continued onsite storage of spent nuclear fuel in licensing proceedings. The BREDL filings were substantially the same as those filed in other COL proceedings in which final environmental impact statements were issued prior to promulgation of the continued storage rule, like North Anna 3. In June 2015, the NRC denied the April 2015 motion and petition.

In August 2015, BREDL filed a petition in the United States Court of Appeals for the District of Columbia Circuit seeking review of the NRC’s June 2015 decision, and Virginia Power intervened. This petition and nine similar petitions relating to other NRC licensing proceedings were held in abeyance pending the outcome of the ongoing judicial review of the NRC’s continued storage rule before the same court. In June 2016, in New York v. NRC, the court upheld the NRC’s continued storage rule. In July 2016, the petitioners in New York v. NRC petitioned for rehearing en banc on their challenge to the continued storage rule, and the court ordered that BREDL’s August 2015 petition pertaining to the application of this rule to North Anna 3, and the similar petitions relating to other NRC proceedings, continue to be held in abeyance until the court’s disposition of the rehearing petition.

Ohio Regulation

PIPP Plus Program

Under the Ohio PIPP Plus Program, eligible customers can make reduced payments based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP amount is deferred and collected under the PIPP Rider in accordance with the rules of the Ohio Commission. In July 2016, East Ohio’s annual update of the PIPP Rider was automatically approved by the Ohio Commission after a 45 day waiting period from the date of the filing. The revised rider rate reflects the recovery over the twelve-month period from July 2016 through June 2017 of projected deferred program costs of approximately $32 million from April 2016 through June 2017, net of a refund for over-recovery of accumulated arrearages of approximately $28 million as of March 31, 2016.

UEX Rider

East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In May 2016, East Ohio filed an application with the Ohio Commission requesting approval to increase its UEX Rider to reflect a refund of over-recovered accumulated bad debt expense of approximately $8 million as of March 31, 2016, and recovery of prospective net bad debt expense projected to total approximately $19 million for the twelve-month period from April 2016 to March 2017. This case is pending.

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West Virginia Regulation

In May 2016, Hope filed a PREP application with the West Virginia Commission requesting approval of a projected capital investment for 2017 of $27 million as part of a total five-year projected capital investment of $152 million. The new PREP customer rates would be effective November 1, 2016. This case is pending.

Dominion Carolina Gas

In June 2016, DCG received FERC authorization to construct and operate the approximately $45 million Columbia to Eastover Project facilities, which are expected to be placed into service in the fourth quarter of 2016.

Note 13. Variable Interest Entities

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

Dominion

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

Dominion has an initial 45% membership interest in Atlantic Coast Pipeline. See Note 9 to the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015 for more details regarding the nature of this entity. Dominion concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion has concluded that it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. Dominion is obligated to provide capital contributions based on its ownership percentage. Dominion’s maximum exposure to loss is limited to its current and future investment.

Dominion and Virginia Power

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

Dominion and Dominion Gas

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

Virginia Power

Virginia Power had long-term power and capacity contracts with five non-utility generators; however, contracts with two of these generators expired in 2015, leaving three non-utility generators with an aggregate summer generation capacity of approximately 418 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2017 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $357 million as of June 30, 2016. Virginia Power paid $37 million and $55 million for electric capacity and $5 million and $23 million for electric energy to these entities in the

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three months ended June 30, 2016 and 2015, respectively. Virginia Power paid $74 million and $108 million for electric capacity and $12 million and $60 million for electric energy to these entities in the six months ended June 30, 2016 and 2015, respectively.

Dominion Gas

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

Virginia Power and Dominion Gas

Virginia Power and Dominion Gas purchased shared services from DRS, an affiliated VIE, of $74 million and $29 million for the three months ended June 30, 2016, $83 million and $30 million for the three months ended June 30, 2015, $188 million and $64 million for the six months ended June 30, 2016 and $166 million and $58 million for the six months ended June 30, 2015, respectively. Virginia Power and Dominion Gas determined that neither is the primary beneficiary of DRS as neither has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power and Dominion Gas. Virginia Power and Dominion Gas have no obligation to absorb more than their allocated shares of DRS costs.

Note 14. Significant Financing Transactions

Credit Facilities and Short-term Debt

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

Dominion

At June 30, 2016, Dominion’s commercial paper and letters of credit outstanding, as well as its capacity available under credit facilities, were as follows:

	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Joint revolving credit facility(1)	$	5,000	$	3,437	$	—	$	1,563
Joint revolving credit facility(1)		500		—		52		448
Total	$	5,500	$	3,437	$	52	$	2,011

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

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

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

(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 June 30, 2016, the aggregate sub-limit for Virginia Power was $2.0 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion. In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

In addition to the credit facility commitments mentioned above, Virginia Power also has a $120 million credit facility. In May 2016, the maturity date for this facility was extended from April 2019 to April 2020. As of June 30, 2016, this facility supports $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. These credit facilities can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

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

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

(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 June 30, 2016, the aggregate sub-limit for Dominion Gas was $1.0 billion. If Dominion Gas has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion. In May 2016, the maturity dates for these facilities were extended from April 2019 to April 2020. These credit facilities can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

Remarketable Subordinated Notes

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

Enhanced Junior Subordinated Notes

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

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

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

Long-term Debt

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

Issuance of Common Stock

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

In December 2014, Dominion filed an SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at-the-market program. Also in December 2014, Dominion entered into four separate sales agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the New York Stock Exchange at market prices or in such other transactions as are agreed upon by Dominion and the sales agents and in conformance with applicable securities laws. Following issuances during the first and second quarters of 2015, Dominion has the ability to issue up to approximately $200 million of stock under the 2014 sales agency agreements; however, no additional issuances have occurred under these agreements in 2016.

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

Note 15. Commitments and Contingencies

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

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Environmental Matters

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

Air

CAA

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

MATS

In December 2011, the EPA issued MATS for coal- and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance was required by April 16, 2015, with certain limited exceptions. However, in June 2014, the VDEQ granted a one-year MATS compliance extension for two coal-fired units at Yorktown power station to defer planned retirements and allow for continued operation of the units to address reliability concerns while necessary electric transmission upgrades are being completed. These coal units will need to continue operating until at least April 2017 due to delays in transmission upgrades needed to maintain electric reliability, 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. The order was signed by the EPA in April 2016 allowing the Yorktown power station units to operate for up to one additional year, as required to maintain reliable power availability while transmission upgrades are being made.

In June 2015, the United States Supreme Court issued a decision holding that the EPA failed to take cost into account when the agency first decided to regulate the emissions from coal- and oil-fired plants, and remanded the MATS rule back to the United States Court of Appeals for the District of Columbia Circuit. However, the Supreme Court did not vacate or stay the effective date and implementation of the MATS rule. In November 2015, in response to the Supreme Court decision, the EPA proposed a supplemental finding that consideration of cost does not alter the agency’s previous conclusion that it is appropriate and necessary to regulate coal- and oil-fired electric utility steam generating units under Section 112 of the CAA. In December 2015, the District of Columbia Court of Appeals issued an order remanding the MATS rulemaking proceeding back to the EPA without setting aside judgment, noting that EPA had represented it was on track to issue a final finding regarding its consideration of cost. In April 2016, the EPA issued a final supplemental finding that consideration of costs does not alter its conclusion regarding appropriateness and necessity for the regulation. These actions do not change Virginia Power’s plans to close coal units at Yorktown power station or the need to complete necessary electricity transmission upgrades by 2017. Since the MATS rule remains in effect and Dominion is complying with the requirements of the rule, Dominion does not expect any adverse impacts to its operations at this time.

CAIR

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

CSAPR

Following numerous petitions by industry participants for review and a successful motion for stay, in October 2014, the United States Court of Appeals for the District of Columbia Circuit ordered that the EPA’s motion to lift the stay of CSAPR be granted. Further, the Court granted the EPA’s request to shift the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets (which would have gone into effect in 2012 and 2013) 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 Dominion’s or Virginia Power’s Consolidated Financial Statements. Future outcomes of any additional litigation and/or any action to issue a revised rule, including the EPA’s recent proposal to reduce the ozone season NO_X emission budgets beginning in 2017, could affect the assessment regarding cost of compliance.

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Ozone Standards

In October 2015, the EPA issued a final rule tightening the ozone standard, set in 2008, 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. To comply with the 2008 standard, in April 2016 Dominion submitted the NO_X Reasonable Available Control Technology analysis for Unit 5 at Possum Point power station. Until the states have developed implementation plans, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significant expenditures are required to implement additional controls, it could adversely affect the Companies’ results of operations and cash flows.

NO_x and VOC Emissions

In April 2014, the Pennsylvania Department of Environmental Protection issued proposed regulations to reduce NO_X and VOC emissions from combustion sources. The regulations were finalized in April 2016. To comply with the regulations, Dominion Gas anticipates installing emission control systems on existing engines at several compressor stations in Pennsylvania. The compliance costs associated with engineering and installation of controls and compliance demonstration with the regulation are expected to be approximately $25 million.

NSPS

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

Methane Emissions

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

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

Climate Change Legislation and Regulation

In October 2013, the United States Supreme Court granted petitions filed by several industry groups, states, and the United States Chamber of Commerce seeking review of the United States Court of Appeals for the District of Columbia Circuit’s June 2012 decision upholding the EPA’s regulation of GHG emissions from stationary sources under the CAA’s permitting programs. In June 2014, the United States Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the EPA’s ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. In July 2014, the EPA issued a memorandum specifying that it will no longer apply or enforce federal regulations or EPA-approved PSD state implementation plan provisions that require new and modified stationary sources to obtain a PSD permit when GHGs are the only pollutant that would be emitted at levels that exceed the permitting thresholds. In August 2015, the EPA published a final rule rescinding the requirement for all new and modified major sources to obtain permits based solely on their GHG emissions. In addition, the EPA stated that it will continue to use the existing thresholds to apply to sources that are otherwise subject to PSD for conventional pollutants until it completes a new rulemaking either justifying and upholding those thresholds or setting new ones. Some states have issued interim guidance that follows the EPA guidance. 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.

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

Water

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

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion and Virginia Power are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. While the impacts of this rule could be material to Dominion’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.

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

Solid and Hazardous Waste

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

From time to time, Dominion, Virginia Power, or Dominion Gas may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion, Virginia Power, or Dominion Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. 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.

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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 and landfill closure costs.

Other Legal Matters

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

Appalachian Gateway

Following the completion of the Appalachian Gateway project in 2012, DTI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DTI filed a complaint in United States District Court for the Eastern District of Virginia for breach of contract as well as accounting and declaratory relief. The contractor filed a motion to dismiss, or in the alternative, a motion to transfer venue to Pennsylvania and/or West Virginia, where the pipelines were constructed. DTI filed an opposition to the contractor’s motion in August 2013. In November 2013, the court granted the contractor’s motion on the basis that DTI must first comply with the dispute resolution process. In July 2015, the contractor filed a complaint against DTI in United States District Court for the Western District of Pennsylvania. In August 2015, DTI filed a motion to dismiss, or in the alternative, a motion to transfer venue to Virginia. In March 2016, the Pennsylvania court granted the motion to dismiss and transferred the case to the United States District Court for the Eastern District of Virginia. In April 2016, the Virginia court issued an order staying the proceedings and ordering mediation. A mediation occurred in May 2016 but was unsuccessful. In July 2016, DTI filed a motion to dismiss. This case is pending. DTI has accrued a liability of $6 million for this matter. Dominion Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.

Ash Pond and Landfill Closure Costs

In September 2014, Virginia Power received a notice from the Southern Environmental Law Center on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at Possum Point power station. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point power station’s historical and active ash storage facilities. A similar notice from the Southern Environmental Law Center on behalf of the Sierra Club was subsequently received related to Chesapeake power station. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum Point power station, Chesapeake and Bremo power stations as settlement of the potential litigation. While the issue is open to potential further negotiations, the Southern Environmental Law Center declined the offer as presented in January 2015 and, in March 2015, filed a lawsuit related to its claims of the alleged CWA violations at Chesapeake power station. Virginia Power filed a motion to dismiss in April 2015, which was denied in November 2015. A trial was held in June 2016. This case is pending. As a result of the December 2014 settlement offer, Virginia Power recognized a charge of $121 million in other operations and maintenance expense in its Consolidated Statements of Income in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2014.

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In April 2015, the EPA’s final rule regulating the management of CCRs stored in impoundments (ash ponds) and landfills was published in the Federal Register. The final rule regulates CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store CCRs. Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. The enactment of the final rule in April 2015 created a legal obligation for Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary. In April 2016, the EPA announced a partial settlement with certain environmental and industry organizations that had challenged the final CCR rule in the United States Court of Appeals for the District of Columbia Circuit. As part of the settlement, certain exemptions included in the final rule for inactive ponds that closed by April 2018 will be removed, resulting in inactive ponds ultimately being subject to the same requirements as existing ponds. In June 2016, the court issued an order approving the settlement, which requires the EPA to modify provisions in the final CCR rule concerning inactive ponds. Virginia Power does not believe this change will substantially impact its closure plans for inactive ponds.

In 2015, Virginia Power recorded a $386 million ARO related to future ash pond and landfill closure costs. Recognition of the ARO also resulted in a $99 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $166 million increase in property, plant, and equipment associated with asset retirement costs, and a $121 million reduction in other noncurrent liabilities related to reversal of the contingent liability described above since the ARO obligation created by the final CCR rule represents similar activities. Virginia Power is in the process of obtaining the necessary permits to complete the work. In February and March 2016, respectively, two parties filed administrative appeals in the Circuit Court for the City of Richmond challenging certain provisions, relating to ash pond dewatering activities, of Possum Point power station’s wastewater discharge permit issued by the VDEQ in January 2016. One of those parties withdrew its appeal in June 2016. Virginia Power cannot predict the financial impact associated with the remaining appeal, but believes that it will not be material. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the increased obligation in 2015.

Cove Point

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

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

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

Nuclear Matters

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

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

Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion requiring implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation have been implemented. The information requests issued by the NRC request each reactor to reevaluate the seismic and external flooding hazards at their site using present-day methods and information, conduct

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

Guarantees, Surety Bonds and Letters of Credit

Dominion

At June 30, 2016, Dominion had issued $73 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of June 30, 2016, Dominion’s exposure under these guarantees was $43 million, primarily related to certain reserve requirements associated with non-recourse financing.

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

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

	Stated Limit		Value(1)
(millions)
Subsidiary debt(2)	$	27	$	27
Commodity transactions(3)		2,074		864
Nuclear obligations(4)		189		81
Cove Point(5)		1,900		—
Solar(6)		1,514		244
Other(7)		420		28
Total	$	6,124	$	1,244

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

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

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

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

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

(6) Includes guarantees 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 June 30, 2016, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $45 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million. The value provided includes certain guarantees that do not have stated limits.

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Additionally, at June 30, 2016, Dominion had purchased $120 million of surety bonds, including $69 million at Virginia Power and $21 million at Dominion Gas, and authorized the issuance of letters of credit by financial institutions of $52 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

Note 16. Credit Risk

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

At June 30, 2016, Dominion’s credit exposure related to energy marketing and price risk management activities totaled $111 million. Of this amount, investment grade counterparties, including those internally rated, represented 88%. No single counterparty, whether investment grade or non-investment grade, exceeded $31 million of exposure.

Credit-Related Contingent Provisions

The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of June 30, 2016 and December 31, 2015, Dominion would have been required to post an additional $4 million and $12 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion had not posted any collateral at June 30, 2016 or December 31, 2015 related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of June 30, 2016 and December 31, 2015 was $13 million and $49 million, respectively, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and Dominion Gas were not material as of June 30, 2016 and December 31, 2015. See Note 9 for further information about derivative instruments.

Note 17. Related-Party Transactions

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

Virginia Power

Transactions with Affiliates

Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity physical forwards and options, to manage commodity price risks associated with purchases of natural gas. As of June 30, 2016, Virginia Power’s derivative assets and liabilities with affiliates were each $36 million and $3 million, respectively. As of December 31, 2015, Virginia Power’s derivative assets and liabilities with affiliates were $13 million and $22 million, respectively. See Note 9 for more information.

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

DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
(millions)
Commodity purchases from affiliates	$	99	$	94	$	244	$	346
Services provided by affiliates(1)		102		107		242		217
Services provided to affiliates		7		5		12		10

(1) Includes capitalized expenditures of $38 million for both the three months ended June 30, 2016 and 2015, respectively, and $77 million and $73 million for the six months ended June 30, 2016 and 2015, respectively.

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

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

Dominion Gas

Transactions with Related Parties

Dominion Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Gas provides transportation and storage services to affiliates. Dominion Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of June 30, 2016 and December 31, 2015, all of Dominion Gas’ commodity derivatives were with affiliates. See Notes 7 and 9 for more information.

Dominion Gas participates in certain Dominion benefit plans as described in Note 18. In Dominion Gas’ Consolidated Balance Sheets at June 30, 2016 and December 31, 2015, amounts due from Dominion associated with these benefit plans included in noncurrent pension and other postretirement benefit assets were $674 million and $652 million, respectively, and amounts due to Dominion at June 30, 2016 and December 31, 2015 included in other deferred credits and other liabilities were immaterial.

DRS and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Gas. Dominion Gas provides certain services to related parties, including technical services. The amounts recognized for these services were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
(millions)
Purchases of natural gas and transportation and storage services from affiliates	$	2	$	2	$	5	$	4
Sales of natural gas and transportation and storage services to affiliates		18		17		35		35
Services provided by related parties(1)		33		34		72		68
Services provided to related parties (2)		33		25		60		45

(1) Includes capitalized expenditures of $14 million and $15 million for the three months ended June 30, 2016 and 2015, respectively, and $24 million for both the six months ended June 30, 2016 and 2015.

(2) Amounts primarily attributable to Atlantic Coast Pipeline.

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

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

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

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

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

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

Note 18. Employee Benefit Plans

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

Dominion

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

	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016			2015
(millions)
Three Months Ended June 30,
Service cost	$	28		$	31		$	8		$	10
Interest cost		78			72			17			16
Expected return on plan assets		(139	)		(133	)		(30	)		(30	)
Amortization of prior service cost (credit)		1			1			(7	)		(6	)
Amortization of net actuarial loss		27			40			2			2
Net periodic benefit cost (credit)	$	(5	)	$	11		$	(10	)	$	(8	)
Six Months Ended June 30,
Service cost	$	57		$	63		$	16		$	20
Interest cost		155			144			34			33
Expected return on plan assets		(278	)		(266	)		(59	)		(59	)
Amortization of prior service cost (credit)		1			1			(14	)		(13	)
Amortization of net actuarial loss		55			80			3			3
Net periodic benefit cost (credit)	$	(10	)	$	22		$	(20	)	$	(16	)

Employer Contributions

During the six months ended June 30, 2016, Dominion made no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs during the remainder of 2016.

Dominion Gas

Dominion Gas participates in certain Dominion benefit plans as described in Note 21 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015. See Note 17 for more information.

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

	Pension Benefits						Other Postretirement Benefits
	2016			2015			2016			2015
(millions)
Three Months Ended June 30,
Service cost	$	4		$	4		$	2		$	1
Interest cost		7			7			4			4
Expected return on plan assets		(34	)		(32	)		(7	)		(6	)
Amortization of net actuarial loss		4			5			1			—
Net periodic benefit credit	$	(19	)	$	(16	)	$	—		$	(1	)
Six Months Ended June 30,
Service cost	$	7		$	7		$	3		$	3
Interest cost		15			14			7			7
Expected return on plan assets		(67	)		(63	)		(12	)		(12	)
Amortization of net actuarial loss		7			10			1			1
Net periodic benefit credit	$	(38	)	$	(32	)	$	(1	)	$	(1	)

Employer Contributions

During the six months ended June 30, 2016, Dominion Gas made no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion Gas expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs, for both employees represented by collective bargaining units and employees not represented by collective bargaining units, during the remainder of 2016.

Note 19. Operating Segments

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

Primary Operating Segment	Description of Operations	Dominion	Virginia Power	Dominion Gas
DVP	Regulated electric distribution	X	X
	Regulated electric transmission	X	X
Dominion Generation	Regulated electric fleet	X	X
	Merchant electric fleet	X
Dominion Energy	Gas transmission and storage(1)	X		X
	Gas distribution and storage	X		X
	Gas gathering and processing	X		X
	LNG import and storage	X
	Nonregulated retail energy marketing(2)	X

(1) Includes remaining producer services activities for Dominion.

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

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

Dominion

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

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

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

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

• DVP ($5 million after-tax);

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

• Dominion Generation ($19 million after-tax).

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 $45 million ($28 million after-tax) net gain on investments held in nuclear decommissioning trust funds.

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

	DVP		Dominion Generation(1)		Dominion Energy(1)		Corporate and Other			Adjustments/ Eliminations(1)			Consolidated Total
(millions)
Three Months Ended June 30, 2016
Total revenue from external customers	$	512	$	1,564	$	391	$	3		$	128		$	2,598
Intersegment revenue		6		2		124		133			(265	)		—
Total operating revenue		518		1,566		515		136			(137	)		2,598
Net income attributable to Dominion		104		171		162		15			—			452
Three Months Ended June 30, 2015
Total revenue from external customers	$	500	$	1,652	$	463	$	4		$	128		$	2,747
Intersegment revenue		5		6		115		144			(270	)		—
Total operating revenue		505		1,658		578		148			(142	)		2,747
Net income (loss) attributable to Dominion		117		250		129		(83	)		—			413
Six Months Ended June 30, 2016
Total revenue from external customers	$	1,068	$	3,257	$	876	$	6		$	312		$	5,519
Intersegment revenue		11		5		302		325			(643	)		—
Total operating revenue		1,079		3,262		1,178		331			(331	)		5,519
Net income (loss) attributable to Dominion		224		416		348		(12	)		—			976
Six Months Ended June 30, 2015
Total revenue from external customers	$	1,064	$	3,641	$	999	$	(9	)	$	461		$	6,156
Intersegment revenue		10		9		425		286			(730	)		—
Total operating revenue		1,074		3,650		1,424		277			(269	)		6,156
Net income (loss) attributable to Dominion		257		512		356		(176	)		—			949

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

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

Virginia Power

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

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

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

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

• DVP ($5 million after-tax); and

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

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

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

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

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

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

	DVP		Dominion Generation		Corporate and Other			Consolidated Total
(millions)
Three Months Ended June 30, 2016
Operating revenue	$	512	$	1,264	$	—		$	1,776
Net income		104		174		2			280
Three Months Ended June 30, 2015
Operating revenue	$	502	$	1,311	$	—		$	1,813
Net income (loss)		117		155		(26	)		246
Six Months Ended June 30, 2016
Operating revenue	$	1,069	$	2,597	$	—		$	3,666
Net income (loss)		222		340		(19	)		543
Six Months Ended June 30, 2015
Operating revenue	$	1,069	$	2,896	$	(15	)	$	3,950
Net income (loss)		257		345		(87	)		515

Dominion Gas

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

In the six months ended June 30, 2016, Dominion Gas reported an after-tax net expense of $2 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segment. In the six months ended June 30, 2015, Dominion Gas reported no amounts for specific items in the Corporate and Other segment.

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

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

	Dominion     Energy		Corporate and Other			Consolidated Total
(millions)
Three Months Ended June 30, 2016
Operating revenue	$	368	$	—		$	368
Net income (loss)		108		(3	)		105
Three Months Ended June 30, 2015
Operating revenue	$	395	$	—		$	395
Net income (loss)		87		(2	)		85
Six Months Ended June 30, 2016
Operating revenue	$	799	$	—		$	799
Net income (loss)		211		(8	)		203
Six Months Ended June 30, 2015
Operating revenue	$	926	$	—		$	926
Net income (loss)		251		(5	)		246

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Contents of MD&A

MD&A consists of the following information:

• Forward-Looking Statements

• Accounting Matters - Dominion

• Dominion

• Results of Operations

• Segment Results of Operations

• Virginia Power

• Results of Operations

• Dominion Gas

• Results of Operations

• Liquidity and Capital Resources - Dominion

• Future Issues and Other Matters - Dominion

Forward-Looking Statements

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

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

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

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

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

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

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

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

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

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

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

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

• Counterparty credit and performance risk;

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

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

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

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• Fluctuations in interest rates or foreign currency exchange rates;

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

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

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

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

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

• The expected timing and likelihood of completion of the Questar Combination, including the terms and conditions of any required regulatory approvals;

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

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

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

• Political and economic conditions, including inflation and deflation;

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

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

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

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

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

• Changes in operating, maintenance and construction costs;

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

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

• Adverse outcomes in litigation matters or regulatory proceedings; and

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

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015.

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

Accounting Matters

Critical Accounting Policies and Estimates

As of June 30, 2016, there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015. The policies disclosed included the accounting for regulated operations, AROs, income taxes, derivative contracts and other instruments at fair value, goodwill and long-lived asset impairment testing and employee benefit plans.

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Dominion

Results of Operations

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

	2016		2015		$ Change
(millions, except EPS)
Second Quarter
Net income attributable to Dominion	$	452	$	413	$	39
Diluted EPS		0.73		0.70		0.03
Year-To-Date
Net income attributable to Dominion	$	976	$	949	$	27
Diluted EPS		1.61		1.60		0.01

Overview

Second Quarter 2016 vs. 2015

Net income attributable to Dominion increased 9%, primarily due to the absence of charges related to ash pond and landfill closure costs at certain utility generation facilities, a decrease in electric utility capacity related expenses and an increase in gains from agreements to convey shale development rights underneath several natural gas storage fields. These increases were partially offset by a decrease in electric utility sales to retail customers from a reduction in cooling degree days.

Year-To-Date 2016 vs. 2015

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

Analysis of Consolidated Operations

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

	Second Quarter							Year-To-Date
	2016		2015		$ Change			2016		2015		$ Change
(millions)
Operating revenue	$	2,598	$	2,747	$	(149	)	$	5,519	$	6,156	$	(637	)
Electric fuel and other energy-related purchases		551		591		(40	)		1,185		1,544		(359	)
Purchased electric capacity		45		90		(45	)		113		184		(71	)
Purchased gas		56		111		(55	)		175		361		(186	)
Net revenue		1,946		1,955		(9	)		4,046		4,067		(21	)
Other operations and maintenance		665		709		(44	)		1,368		1,311		57
Depreciation, depletion and amortization		361		339		22			712		682		30
Other taxes		139		134		5			303		299		4
Other income		72		56		16			126		116		10
Interest and related charges		239		221		18			465		444		21
Income tax expense		152		190		(38	)		331		489		(158	)

An analysis of Dominion’s results of operations follows:

Second Quarter 2016 vs. 2015

Net revenue decreased 1%, primarily reflecting:

• A $25 million decrease from merchant generation operations, primarily due to lower volumes mainly from increased planned and unplanned outage days in the second quarter of 2016 ($59 million), partially offset by higher realized prices ($14 million) and an increase due to additional solar generating facilities ($9 million); and

• An $8 million decrease from regulated natural gas transmission operations, primarily due to decreased demand charges.

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

• A net decrease in capacity related expenses ($43 million);

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• An increase from rate adjustment clauses ($33 million); and

• An increase in sales to customers due to the effect of changes in customer usage and other factors ($7 million); partially offset by

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

Other operations and maintenance decreased 6%, primarily reflecting:

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

• An increase in gains from agreements to convey shale development rights underneath several natural gas storage fields ($34 million).

These decreases were partially offset by:

• A $40 million increase in planned outage costs primarily due to an increase in scheduled outage days at certain merchant generation facilities; and

• A $16 million increase in storm damage and service restoration costs.

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

Year-To-Date 2016 vs. 2015

Net revenue decreased 1%, primarily reflecting:

• A $42 million decrease from regulated natural gas distribution operations, primarily due to a decrease in rate adjustment clause revenue related to low income assistance programs ($34 million) and a decrease in sales to customers due to a reduction in heating degree days ($11 million);

• A $39 million decrease from merchant generation operations, primarily due to lower volumes mainly from increased planned and unplanned outage days ($63 million), partially offset by an increase due to additional solar generating facilities ($16 million); and

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

• A $31 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($19 million), decreased fuel retained ($11 million) and decreased regulated gas sales ($13 million), partially offset by DCG activities ($10 million); and

• A $9 million decrease in NGL activities, due to decreased volumes ($7 million) and prices ($2 million); partially offset by

• A $15 million increase due to services performed for Atlantic Coast Pipeline.

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

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

• A net decrease in capacity related expenses ($66 million); and

• An increase from rate adjustment clauses ($51 million); partially offset by

• A decrease in sales to retail customers from reductions in cooling and heating degree days ($132 million).

Other operations and maintenance increased 4%, primarily reflecting:

• Organizational design initiative costs ($64 million);

• A decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields ($31 million);

• A $39 million increase in planned outage costs primarily due to an increase in scheduled outage days at certain merchant generation facilities;

• A $19 million increase in storm damage and service restoration costs; and

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

These increases were partially offset by:

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

• A decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs ($34 million). These bad debt expenses are recovered through rates and do not impact net income.

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Income tax expense decreased 32%, primarily due to higher anticipated renewable energy investment tax credits ($90 million), lower pretax income ($48 million) and the impact of a state legislative change ($17 million).

Segment Results of Operations

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

	Net Income attributable to Dominion									Diluted EPS
	2016			2015			$ Change			2016			2015			$ Change
(millions, except EPS)
Second Quarter
DVP	$	104		$	117		$	(13	)	$	0.17		$	0.20		$	(0.03	)
Dominion Generation(1)		171			250			(79	)		0.28			0.42			(0.14	)
Dominion Energy(1)		162			129			33			0.26			0.22			0.04
Primary operating segments		437			496			(59	)		0.71			0.84			(0.13	)
Corporate and Other		15			(83	)		98			0.02			(0.14	)		0.16
Consolidated	$	452		$	413		$	39		$	0.73		$	0.70		$	0.03
Year-To-Date
DVP	$	224		$	257		$	(33	)	$	0.37		$	0.43		$	(0.06	)
Dominion Generation(1)		416			512			(96	)		0.69			0.87			(0.18	)
Dominion Energy(1)		348			356			(8	)		0.57			0.60			(0.03	)
Primary operating segments		988			1,125			(137	)		1.63			1.90			(0.27	)
Corporate and Other		(12	)		(176	)		164			(0.02	)		(0.30	)		0.28
Consolidated	$	976		$	949		$	27		$	1.61		$	1.60		$	0.01

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

DVP

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

	Second Quarter							Year-To-Date
	2016		2015		% Change			2016		2015		% Change
Electricity delivered (million MWh)		18.9		20.1		(6	)%		40.1		43.0		(7	)%
Degree days (electric distribution service area):
Cooling		425		645		(34	)		429		645		(33	)
Heating		367		214		71			2,247		2,578		(13	)
Average electric distribution customer accounts (thousands)(1)		2,545		2,521		1			2,543		2,519		1

(1) Period average.

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

	Second Quarter 2016 vs. 2015 Increase (Decrease)						Year-To-Date 2016 vs. 2015 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(11	)	$	(0.02	)	$	(26	)	$	(0.04	)
Other		—			—			(5	)		(0.01	)
FERC transmission equity return		10			0.02			21			0.04
Storm damage and service restoration		(10	)		(0.02	)		(12	)		(0.02	)
Other		(2	)		—			(11	)		(0.02	)
Share dilution		—			(0.01	)		—			(0.01	)
Change in net income contribution	$	(13	)	$	(0.03	)	$	(33	)	$	(0.06	)

Dominion Generation

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

	Second Quarter							Year-To-Date
	2016		2015		% Change			2016		2015		% Change
Electricity supplied (million MWh):
Utility		20.1		20.4		(1	)%		42.3		43.3		(2	)%
Merchant		6.2		6.6		(6	)		13.3		13.0		2
Degree days (electric utility service area):
Cooling		425		645		(34	)		429		645		(33	)
Heating		367		214		71			2,247		2,578		(13	)

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

	Second Quarter 2016 vs. 2015 Increase (Decrease)						Year-To-Date 2016 vs. 2015 Increase (Decrease)
	Amount			EPS			Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(23	)	$	(0.04	)	$	(54	)	$	(0.09	)
Other		5			0.01			2			—
Renewable energy investment tax credits(1)		(30	)		(0.05	)		(31	)		(0.05	)
Capacity related expenses		26			0.04			40			0.07
Outage costs		(24	)		(0.04	)		(23	)		(0.04	)
Merchant generation margin		(20	)		(0.03	)		(28	)		(0.05	)
Rate adjustment clause equity return		10			0.02			16			0.03
Other		(23	)		(0.04	)		(18	)		(0.03	)
Share dilution		—			(0.01	)		—			(0.02	)
Change in net income contribution	$	(79	)	$	(0.14	)	$	(96	)	$	(0.18	)

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

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Dominion Energy

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

	Second Quarter							Year-To-Date
	2016		2015		% Change			2016		2015		% Change
Gas distribution throughput (bcf):
Sales		3		3		—	%		16		19		(16	)%
Transportation		99		90		10			258		252		2
Heating degree days (gas distribution service area)		729		568		28			3,413		4,143		(18	)
Average gas distribution customer accounts (thousands)(1):
Sales		224		231		(3	)		233		239		(3	)
Transportation		1,079		1,069		1			1,073		1,065		1
Average retail energy marketing customer accounts (thousands)(1)		1,376		1,288		7			1,364		1,269		7

(1) Period average.

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

	Second Quarter 2016 vs. 2015 Increase (Decrease)					Year-To-Date 2016 vs. 2015 Increase (Decrease)
	Amount		EPS			Amount			EPS
(millions, except EPS)
Gas distribution margin:
Weather	$	1	$	—		$	(7	)	$	(0.01	)
Other		1		—			6			0.01
Assignment of shale development rights		21		0.04			(20	)		(0.03	)
Retail energy marketing operations		6		0.01			9			0.01
Other		4		—			4			—
Share dilution		—		(0.01	)		—			(0.01	)
Change in net income contribution	$	33	$	0.04		$	(8	)	$	(0.03	)

Corporate and Other

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

	Second Quarter									Year-To-Date
	2016			2015			$ Change			2016			2015			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	12		$	(17	)	$	29		$	(26	)	$	(62	)	$	36
Specific items attributable to corporate operations		(1	)		1			(2	)		(11	)		(2	)		(9	)
Total specific items		11			(16	)		27			(37	)		(64	)		27
Other corporate operations:
Renewable energy investment tax credits		51			4			47			132			10			122
Other		(47	)		(71	)		24			(107	)		(122	)		15
Total other corporate operations		4			(67	)		71			25			(112	)		137
Total net income (expense)	$	15		$	(83	)	$	98		$	(12	)	$	(176	)	$	164
EPS impact	$	0.02		$	(0.14	)	$	0.16		$	(0.02	)	$	(0.30	)	$	0.28

Total Specific Items

Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing those segments’ performance or in allocating resources. See Note 19 to the Consolidated Financial Statements in this report for discussion of these items in more detail.

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Virginia Power

Results of Operations

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

	Second Quarter						Year-To-Date
	2016		2015		$ Change		2016		2015		$ Change
(millions)
Net income	$	280	$	246	$	34	$	543	$	515	$	28

Overview

Second Quarter 2016 vs. 2015

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

Year-To-Date 2016 vs. 2015

Net income increased 5%, primarily due to the absence of the write-off of deferred fuel costs associated with Virginia legislation enacted in February 2015, a decrease in capacity related expenses and a decrease in charges related to ash pond and landfill closure costs at certain utility generation facilities. These increases were partially offset by a decrease in sales to retail customers from reductions in cooling and heating degree days.

Analysis of Consolidated Operations

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

	Second Quarter							Year-To-Date
	2016		2015		$ Change			2016		2015		$ Change
(millions)
Operating revenue	$	1,776	$	1,813	$	(37	)	$	3,666	$	3,950	$	(284	)
Electric fuel and other energy-related purchases		475		497		(22	)		1,011		1,307		(296	)
Purchased electric capacity		45		90		(45	)		113		184		(71	)
Net revenue		1,256		1,226		30			2,542		2,459		83
Other operations and maintenance		386		445		(59	)		836		841		(5	)
Depreciation and amortization		247		231		16			495		469		26
Other taxes		70		69		1			144		143		1
Other income		18		21		(3	)		34		36		(2	)
Interest and related charges		113		108		5			227		216		11
Income tax expense		178		148		30			331		311		20

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

Second Quarter 2016 vs. 2015

Net revenue increased 2%, primarily reflecting:

• A net decrease in capacity related expenses ($43 million);

• An increase from rate adjustment clauses ($33 million); and

• An increase in sales to customers due to the effect of changes in customer usage and other factors ($7 million); partially offset by

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

Other operations and maintenance decreased 13%, primarily reflecting:

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

• A $10 million decrease in salaries, wages and benefits and general administrative expenses; partially offset by

• A $16 million increase in storm damage and service restoration costs.

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

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Year-To-Date 2016 vs. 2015

Net revenue increased 3%, primarily reflecting:

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

• A net decrease in capacity related expenses ($66 million); and

• An increase from rate adjustment clauses ($51 million); partially offset by

• A decrease in sales to retail customers from a reduction in cooling and heating degree days ($132 million).

Other operations and maintenance decreased 1%, primarily reflecting:

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

• A $6 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income; and

• A $6 million decrease in outside services; partially offset by

• Organizational design initiative costs ($32 million); and

• A $19 million increase in storm damage and service restoration costs.

Dominion Gas

Results of Operations

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

	Second Quarter						Year-To-Date
	2016		2015		$ Change		2016		2015		$ Change
(millions)
Net income	$	105	$	85	$	20	$	203	$	246	$	(43	)

Overview

Second Quarter 2016 vs. 2015

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

Year-To-Date 2016 vs. 2015

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

Analysis of Consolidated Operations

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

	Second Quarter							Year-To-Date
	2016		2015		$ Change			2016		2015		$ Change
(millions)
Operating revenue	$	368	$	395	$	(27	)	$	799	$	926	$	(127	)
Purchased gas		16		21		(5	)		50		95		(45	)
Other energy-related purchases		1		7		(6	)		4		13		(9	)
Net revenue		351		367		(16	)		745		818		(73	)
Other operations and maintenance		74		124		(50	)		198		198		—
Depreciation and amortization		52		53		(1	)		95		104		(9	)
Other taxes		39		37		2			91		92		(1	)
Other income		9		4		5			15		13		2
Interest and related charges		23		18		5			45		35		10
Income tax expense		67		54		13			128		156		(28	)

An analysis of Dominion Gas’ results of operations follows:

Second Quarter 2016 vs. 2015

Net revenue decreased 4%, primarily reflecting:

• A $12 million decrease from regulated natural gas transmission operations, primarily reflecting:

• A $17 million decrease in gas transportation and storage activities, primarily due to decreased demand charges; and

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• A $3 million decrease in NGL activities primarily due to decreased volumes; partially offset by

• An $8 million increase due to services performed for Atlantic Coast Pipeline; and

• A $5 million decrease from regulated natural gas distribution operations, primarily reflecting a decrease in rate adjustment clause revenue related to low income assistance programs ($7 million), partially offset by an increase in AMR and PIR program revenues ($2 million).

Other operations and maintenance decreased 40%, primarily reflecting:

• An increase in gains from agreements to convey shale development rights underneath several natural gas storage fields ($34 million);

• A decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs ($7 million). These bad debt expenses are recovered through rates and do not impact net income; and

• A $8 million decrease in salaries, wages and benefits and general administrative expenses; partially offset by

• An $8 million increase due to services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income.

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

Interest and related charges increased 28%, primarily due to higher interest expense on long-term debt resulting from a debt issuance in November 2015.

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

Year-To-Date 2016 vs. 2015

Net revenue decreased 9%, primarily reflecting:

• An $38 million decrease from regulated natural gas distribution operations, primarily reflecting:

• A decrease in rate adjustment clause revenue related to low income assistance programs ($34 million); and

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

• An increase in AMR and PIR program revenues ($7 million); and

• A $36 million decrease from regulated natural gas transmission operations, primarily reflecting:

• A $41 million decrease in gas transportation and storage activities, primarily due to decreased demand charges ($21 million), decreased regulated gas sales ($13 million) and decreased fuel retained ($10 million); and

• A $9 million decrease in NGL activities, due to decreased volumes ($7 million) and prices ($2 million); partially offset by

• A $15 million increase due to services performed for Atlantic Coast Pipeline.

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

• A decrease in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs ($34 million). These bad debt expenses are recovered through rates and do not impact net income;

• A $9 million decrease in salaries, wages and benefits and general administrative expenses;

• A decrease in gains from agreements to convey shale development rights underneath several natural gas storage fields ($31 million);

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

• Organizational design initiative costs ($8 million).

Interest and related charges increased 29%, primarily due to higher interest expense on long-term debt resulting from a debt issuance in November 2015.

Income tax expense decreased 18%, primarily reflecting lower pre-tax income.

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.

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

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

At June 30 2016, Dominion had $2.0 billion of unused capacity under its credit facilities.

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

	2016			2015
(millions)
Cash and cash equivalents at January 1	$	607		$	318
Cash flows provided by (used in):
Operating activities		2,018			2,160
Investing activities		(3,725	)		(3,084	)
Financing activities		1,477			877
Net decrease in cash and cash equivalents		(230	)		(47	)
Cash and cash equivalents at June 30	$	377		$	271

Operating Cash Flows

Net cash provided by Dominion’s operating activities decreased $142 million, primarily due to higher net margin collateral requirements and the impact from unfavorable weather in 2016, partially offset by higher deferred fuel cost recoveries in its Virginia jurisdiction.

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

Dominion’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, which are discussed in Item 1A. Risk Factors in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015.

Credit Risk

Dominion’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion’s credit exposure as of June 30, 2016 for these activities. Gross credit exposure for each counterparty is calculated prior to the application of collateral and represents outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade(1)	$	87	$	31	$	56
Non-investment grade(2)		2		—		2
No external ratings:
Internally rated - investment grade(3)		11		—		11
Internally rated - non-investment grade(4)		11		1		10
Total	$	111	$	32	$	79

(1) Designations as investment grade are based upon minimum credit ratings assigned by Moody’s Investors Service and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 63% of the total net credit exposure.

(2) The five largest counterparty exposures, combined, for this category represented approximately 2% 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 4% of the total net credit exposure.

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Investing Cash Flows

Net cash used in Dominion’s investing activities increased $641 million, primarily due to higher capital expenditures and the restricted cash for the Questar Combinations, partially offset by the absences of Dominion’s acquisition of DCG and the acquisition 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, 2015, the ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

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

Net cash provided by Dominion’s financing activities increased $600 million, primarily reflecting an increase in common stock issuances.

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

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In the Credit Ratings section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015, there is a discussion on the use of capital markets by Dominion as well as the impact of credit ratings on the accessibility and costs of using these markets.

In March 2016, Fitch Ratings Ltd. and Standard & Poor’s changed the rating for Dominion’s junior subordinated debt securities to account for its inability to defer interest payments on the remarketed 2013 Series A RSNs. Junior subordinated debt securities with an interest deferral feature are rated one notch lower by Fitch Ratings Ltd. and Standard & Poor’s (BBB-) than junior subordinated debt securities without an interest deferral feature (BBB). See Note 14 to the Consolidated Financial Statements for a description of the remarketed notes. As of June 30, 2016, there have been no additional changes in Dominion’s credit ratings.

Debt Covenants

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

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of June 30, 2016, there have been no material changes outside the ordinary course of business to Dominion’s contractual obligations nor any material changes to planned capital expenditures as disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015.

Use of Off-Balance Sheet Arrangements

As of June 30, 2016, with the exception of the leasing arrangement described herein, there have been no material changes in the off-balance sheet arrangements disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015.

Leasing Arrangement

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

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

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

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

Future Issues and Other Matters

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

Environmental Matters

Dominion is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. See Note 22 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015, and Note 15 to the Consolidated Financial Statements in this report for additional information on various environmental matters.

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

Legal Matters

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

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Regulatory Matters

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

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ITEM 3.

QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

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

Market Risk Sensitive Instruments and Risk Management

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

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

Commodity Price Risk

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

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

A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease in fair value of $20 million and $24 million of Dominion’s commodity-based derivative instruments as of June 30, 2016 and December 31, 2015, respectively.

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

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

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

Interest Rate Risk

The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt and interest rate swaps designated under fair value hedging and outstanding for the Companies, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at June 30, 2016 or December 31, 2015.

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

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

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in a decrease of $52 million and $42 million, respectively, in the fair value of Dominion’s and Virginia Power’s interest rate derivatives at June 30, 2016. As of December 31, 2015, Dominion, Virginia Power and Dominion Gas had $4.6 billion, $2.0 billion and $250 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $71 million, $52 million and $2 million, respectively, in the fair value of Dominion’s, Virginia Power’s and Dominion Gas’ interest rate derivatives at December 31, 2015.

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

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

Investment Price Risk

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

Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $67 million and $102 million for the six months ended June 30, 2016 and 2015, respectively, and $184 million for the year ended December 31, 2015. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion recorded in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $98 million for the six months ended June 30, 2016. Dominion recorded in AOCI and regulatory liabilities, a net decrease in unrealized gains on these investments of $62 million for the six months ended June 30, 2015 and $157 million for the year ended December 31, 2015.

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

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

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ITEM 4. CONTROLS AND PROCEDURES

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

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

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

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

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

• Notes 12 and 15 in this report.

ITEM 1A. RISK FACTORS

The Companies businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond the Companies’ control. A number of these risk factors have been identified in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015, which should be taken into consideration when reviewing the information contained in this report. There have been no material changes with regard to the risk factors previously disclosed in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2015. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A in this report.

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

Dominion

ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares (or Units) Purchased(1)		Average Price Paid per Share (or Unit)(2)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs(3)
4/1/16-4/30/16		1,639	$	75.39		—	19,629,059 shares/ $1.18 billion
5/1/16-5/31/16		6,739		71.47		—	19,629,059 shares/ $1.18 billion
6/1/16-6/30/16		1,527		71.68		—	19,629,059 shares/ $1.18 billion
Total		9,905	$	72.15		—	19,629,059 shares/ $1.18 billion

(1) In April, May and June 2016, 1,639 shares, 6,739 shares and 1,527 shares, respectively, were tendered by employees to satisfy tax withholding obligations on vested restricted stock.

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

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

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ITEM 6. EXHIBITS

Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas
3.1.a	Dominion Resources, Inc. Articles of Incorporation as amended and restated, effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).	X
3.1.b	Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255).		X
3.1.c	Articles of Organization of Dominion Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).			X
3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective December 17, 2015 (Exhibit 3.1, Form 8-K filed December 17, 2015, File No. 1-8489).	X
3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).		X
3.2.c	Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066).			X
4	Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.	X	X	X
4.1	Indenture, dated as of October 1, 2013, between Dominion Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form S-4 filed April 4, 2014, File No. 333-195066); First Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.2, Form S-4 filed April 4, 2014, File No. 333-195066); Second Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.3, Form S-4 filed April 4, 2014, File No. 333-195066); Third Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.4, Form S-4 filed April 4, 2014, File No. 333-195066); Fourth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.2, Form 8-K filed December 8, 2014, File No. 333-195066); Fifth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.3, Form 8-K filed December 8, 2014, File No. 333-195066); Sixth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.4, Form 8-K filed December 8, 2014, File No. 333-195066); Seventh Supplemental Indenture, dated as of November 1, 2015 (Exhibit 4.2, Form 8-K filed November 17, 2015, File No. 001-37591); Eighth Supplemental Indenture, dated as of May 1, 2016 (filed herewith); Ninth Supplemental Indenture, dated as of June 1, 2016 (filed herewith); Tenth Supplemental Indenture, dated as of June 1, 2016 (filed herewith).	X		X
4.2	Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2013, File No. 1-8489); Eighth Supplemental Indenture, dated March 7, 2016 (Exhibit 4.4, Form 8-K filed March 7, 2016, File No. 1-8489); Ninth Supplemental Indenture, dated May 26, 2016 (Exhibit 4.4, Form 8-K filed May 26, 2016, File No. 1-8489); Tenth Supplemental Indenture, dated as of July 1, 2016 (Exhibit 4.3, Form 8-K filed July 19, 2016, File No. 1-8489).	X
12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X

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Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas
12.2	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).		X
12.3	Ratio of earnings to fixed charges for Dominion Gas Holdings, LLC (filed herewith).			X
31.a	Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.b	Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.c	Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
31.d	Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
31.e	Certification by Chief Executive Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).			X
31.f	Certification by Chief Financial Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).			X
32.a	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).	X
32.b	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X
32.c	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).			X
99	Condensed consolidated earnings statements (filed herewith).	X	X	X
101	The following financial statements from Dominion Resources, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, filed on August 3, 2016, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statement of Equity, (iv) Consolidated Statements of Comprehensive Income, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Virginia Electric and Power Company’s and Dominion Gas Holdings, LLC’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, filed on August 3, 2016, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.	X	X	X

* Indicates management contract or compensatory plan or arrangement

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SIGNATURE

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

	DOMINION RESOURCES, INC. Registrant
August 3, 2016	/s/ Michele L. Cardiff
	Michele L. Cardiff Vice President, Controller and Chief Accounting Officer
	VIRGINIA ELECTRIC AND POWER COMPANY Registrant
August 3, 2016	/s/ Michele L. Cardiff
	Michele L. Cardiff Vice President, Controller and Chief Accounting Officer
	DOMINION GAS HOLDINGS, LLC Registrant
August 3, 2016	/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 December 17, 2015 (Exhibit 3.1, Form 8-K filed December 17, 2015, File No. 1-8489).	X
3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).		X
3.2.c	Operating Agreement of Dominion Gas Holdings, LLC dated as of September 12, 2013 (Exhibit 3.2, Form S-4 filed April 4, 2014, File No. 333-195066).			X
4	Dominion Resources, Inc., Virginia Electric and Power Company and Dominion Gas Holdings, LLC agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.	X	X	X
4.1	Indenture, dated as of October 1, 2013, between Dominion Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form S-4 filed April 4, 2014, File No. 333-195066); First Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.2, Form S-4 filed April 4, 2014, File No. 333-195066); Second Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.3, Form S-4 filed April 4, 2014, File No. 333-195066); Third Supplemental Indenture, dated as of October 1, 2013 (Exhibit 4.4, Form S-4 filed April 4, 2014, File No. 333-195066); Fourth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.2, Form 8-K filed December 8, 2014, File No. 333-195066); Fifth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.3, Form 8-K filed December 8, 2014, File No. 333-195066); Sixth Supplemental Indenture, dated as of December 1, 2014 (Exhibit 4.4, Form 8-K filed December 8, 2014, File No. 333-195066); Seventh Supplemental Indenture, dated as of November 1, 2015 (Exhibit 4.2, Form 8-K filed November 17, 2015, File No. 001-37591); Eighth Supplemental Indenture, dated as of May 1, 2016 (filed herewith); Ninth Supplemental Indenture, dated as of June 1, 2016 (filed herewith); Tenth Supplemental Indenture, dated as of June 1, 2016 (filed herewith).	X		X
4.2	Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Fourth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.3, Form 8-K filed June 7, 2013, File No. 1-8489); Fifth Supplemental Indenture, dated as of June 1, 2013 (Exhibit 4.4, Form 8-K filed June 7, 2013, File No. 1-8489); Sixth Supplemental Indenture, dated as of June 1, 2014 (Exhibit 4.3, Form 8-K filed July 1, 2014, File No. 1-8489); Seventh Supplemental Indenture, dated as of September 1, 2014 (Exhibit 4.3, Form 8-K filed October 3, 2013, File No. 1-8489); Eighth Supplemental Indenture, dated March 7, 2016 (Exhibit 4.4, Form 8-K filed March 7, 2016, File No. 1-8489); Ninth Supplemental Indenture, dated May 26, 2016 (Exhibit 4.4, Form 8-K filed May 26, 2016, File No. 1-8489); Tenth Supplemental Indenture, dated as of July 1, 2016 (Exhibit 4.3, Form 8-K filed July 19, 2016, File No. 1-8489).	X
12.1	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).	X

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Exhibit Number	Description	Dominion	Virginia Power	Dominion Gas
12.2	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).		X
12.3	Ratio of earnings to fixed charges for Dominion Gas Holdings, LLC (filed herewith).			X
31.a	Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.b	Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).	X
31.c	Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
31.d	Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X
31.e	Certification by Chief Executive Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).			X
31.f	Certification by Chief Financial Officer of Dominion Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).			X
32.a	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).	X
32.b	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X
32.c	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).			X
99	Condensed consolidated earnings statements (filed herewith).	X	X	X
101	The following financial statements from Dominion Resources, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, filed on August 3, 2016, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statement of Equity, (iv) Consolidated Statements of Comprehensive Income, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Virginia Electric and Power Company’s and Dominion Gas Holdings, LLC’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, filed on August 3, 2016, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.	X	X	X

* Indicates management contract or compensatory plan or arrangement

101